Due to discharge lines being larger than the discharge nozzle, eccentric reducers are required in the line.
Reducers should be as close as possible to the nozzle; with top suction-top discharge pumps, care must be taken to ensure that the flats on eccentric reducers are orientated so that the lines do not foul each other.
A pressure gauge should be located in the discharge line, upstream of the check and isolation valves.
When a level switch for pump protection is installed in the discharge line, upstream of the block valves, ensure good access for maintenance of switch.
To enable good access to valve handwheels and ease of supporting, the discharge line should be turned flat after the reducer, and the line angled away from the nozzle to enable the line to be supported from grade.
Avoid supporting large lines from pipe-rack structures if possible, this enables minimum-size beam sections to be used and better access for pump removal and maintenance.
Before drawing the reducer, the length of the fitting must be found on the Welded Fittings–Flanges Dimensioning Chart (see Figure 3.47). The H dimension will provide the end-to-end length for either the concentric or eccentric reducer.
NOTE: Always use the H dimension of the large end when determining the fitting length of any reducing fitting.
Figure 3.48 represents the step-by-step procedures used to draw a 16″×14″ concentric reducer. Figure 3.49 shows the step-by-step procedures that a 10″×8″ eccentric reducer, flat on bottom, is drawn with.
Step 1. Using the H dimension found on the Welded Fittings–Flanges Dimensioning Chart, draw a centerline 14″ long.
Step 2. Measure 8″ (one-half the 16″ large end size) on each side of the centerline on one end of the centerline and 7″ (one-half the 14″ small end size) on each side of the opposite end of the centerline.
Step 3. Connect the opposing ends of the fitting by drawing lines from endpoint to endpoint.
Step 4. Darken the sides and weld lines of the reducer then add the connecting pipe.
Step 1. To represent the large diameter end of the reducer, draw a vertical LINE 10” long (NPS), having a 0.53mm lineweight.
Step 2. Draw a horizontal LINE perpendicular and to the right measuring 7” (H dimension from Welded Fittings-Flanges chart), which will represent the length of the reducer.
Step 3. Create the small diameter end of the reducer by drawing an 8” (NPS) vertical LINE up from the right end of the reducer.
Step 4. Complete the eccentric reducer by drawing a sloping LINE back to the top of the 10” line, connecting the two vertical ends. Add the reducer’s weld dots with the DONUT command. The DONUT will have an inside diameter of 0” and outside diameter of 1.75”. TRIM the weld dots so that only one-half of the dot is visible.
Reducers are used to reduce or expand the line size. There are two types of reducers: concentric and eccentric (Fig. 14.26).
In a concentric reducer, the reduction is concentric and the centerline of the pipe remains aligned with the pipe. Fig. 14.27 shows a concentric reducer.
The bottom of pipe is changing due to having a concentric reducer in the line. In an eccentric reducer, there is eccentricity between the centerline of the bigger end and the centerline of the smaller end. An eccentric reducer has offset centerlines, as shown in Fig. 14.28.
The amount of offset in an eccentric reducer is defined as this formula:
A concentric reducer is used in pipe racks to maintain a constant bottom of pipe (BOP). Pipe supports within a pipe rack have the same elevation, so the piping system should have a consistent BOP to rest on each support.
An eccentric reducer is used upstream of pumps to increase the fluid velocity and provide a net positive suction head. A reducer is also installed upstream and downstream of pressure safety valves (PSVs) in flare lines. The other application of an eccentric reducer is to increase the line size to 4″ for thermowell (temperature gauge) installation. An eccentric reducer does not change the bottom of the pipe and support height. Fig. 14.29 shows how to put the reducer before the pump.
Elbows, like other fittings, can have butt weld, socket weld, or thread connections. Applicable pressure ratings, dimensional standards, and material standards are as per the ASME B16.9 standard. This standard covers all the wrought fittings with butt weld connections. Socket and thread end elbows are covered by the ASME B16.11 standard.
Swages are functionally the same as reducers, which are used in small sizes of screwed and socket connections (Fig. 14.30). The short length of a reducer probably does not allow enough space to have a thread or socket on both ends. Swages are longer than reducers. Swages, like reducers, are in both eccentric and concentric types. Swages can have three types endings—socket, thread, and beveled end on both sides (Fig. 14.31). Swages are also called swage nipples.
There are choices that can be made in the installation and pump selection that can conserve energy. The selection of the most efficient pumps and motors capable of doing the job is one area. Piping is another area. Pipe sizing is normally a compromise between first cost and operating costs but another area that is often overlooked is the optimal recovery of the kinetic energy in the pump discharge. Many times the discharge size of a pump is specified small, to allow the use of lower cost valves at the discharge and then expanded up by means of eccentric reducers.
The use of concentric reducers should be considered since they are much more effective at converting the velocity pressure to static pressure. The use of a conical 7° diffuser would result in a recovery of approximately 90%14 whereas an eccentric reducer could have a estimated best case recovery of 55%. If the velocity head at the discharge flange is 3 m (10 ft.), then 2.7 m or 9 ft. would be recovered by the conical diffuser as opposed to the 1.65 m or 5.5 ft. recovery of the eccentric reducer. This is a difference of 1.05 m or 3.5 ft. Some of the unrecovered kinetic energy would be recovered later in the pipe, just as in a sudden expansion. Taking this recovery as being 50%, we are now showing 1.75 ft. unrecovered, or an equivalent power loss of almost 2%. Fig. 1.14 shows the result of a study by the U S Department of Energy, namely 240 billion kwh/yr potential savings in pump installations due to improvement in motor efficiency, electrical distribution correction, motor drive/mechanical system matching e.g. adjustable speed drives, and process automation. While electrical distribution may or may not be controllable by the user, the other three more significant factors of high efficiency motors, system matching and process optimization are.
The design of pump suction piping is particularly important. It should be arranged so as to minimize head loss (i.e., be as short and straight as possible, with minimum valves and obstructions to flow).
When vessels are elevated, suction lines are preferably routed overhead with top suction connections to pumps.
Any reduction in horizontal suction line size required at the pump flange should be made with eccentric reducers with the bottom straight for pumps taking suction from below; and the top straight for pumps fed from above.
All overhead pump suction lines should be arranged to drain from the equipment toward the pump without inverted pockets. Any changes in the direction of suction lines should be at least 600 mm from the pumps to avoid unbalanced incoming flow.
Any increase in size in non-vertical discharge lines should be achieved using eccentric reducers, arranged with bottom straight for delivery above pump, and top straight for delivery below. Discharge lines with flowmeters should preferably run vertically from the top of the pump to just above headroom height and then horizontally to the piperack (but see Section 36.5). Positioning of flowmeters has to take account of flow disturbance and the required number of pipeline diameters upstream and downstream from the meter of any obstruction to flow.
Provision should be made to isolate the pump from the feed vessel when it leaks or otherwise malfunctions so that it can be replaced without draining the vessel. Isolation should be provided on the discharge side in such a way that also allows safe access to any nonreturn valves and instrumentation.
As we discussed in the last chapter, the only way to manage the risk of internal corrosion in steel pipes is by removing any standing water. It should have been clear in the last section that drip traps are only effective at removing the liquid that happens to arrive at the trap. Liquid that accumulates away from drip traps is a serious corrosion risk and will often have detrimental impacts on your ability to control operating pressure at well-sites. Finally, accumulated liquid can become mobile for reasons and at times not of our choosing, and the resulting slugs can do real harm.
It is critical that we manage liquid accumulations as part of an ongoing, carefully considered plan. The only way to manage these liquid accumulations is to run a device through the line to displace the liquid toward some piece of equipment that can capture it. This device is called a “pig.” There are many apocryphal stories about where the name came from. It has been proposed that it is an acronym, and it has been proposed that the name comes from the squealing sound it makes as it travels down the pipe. The acronyms are sometimes humorous (such as “pipeline inspection gadget”), but incorrect. The persistent story is that early pigs were made of straw wrapped in wire and the sound was distinctive. The sound of a pig traveling down a pipe is rarely distinguishable from the background flow sounds and when it is noticeable it doesn’t sound much like a “squeal.” The actual genesis of the name is that early pigs were round, fat, and the end tapered toward something that looks slightly like a pig’s snout. That was the limit of thought that went into naming this ubiquitous device.
Pigs are used for many specific tasks. Pigs to remove liquid are fairly simple and increasingly the industry is using “Turbo Pigs” (“Turbo Pig” is a registered trademark of Girard Industries) which are reusable resilient plastic with a central core and a number of cups or wipers. See the pigs toward the right-hand side and the small pig in front on the left-hand side of Fig. 6.13, but many people still prefer the traditional “bullet” or porcine shape. If you need to clean the pipe walls of solids accumulations, the pigs with brushes are available in both the Turbo style and the traditional porcine shape.
Today’s pigs are available in the traditional porcine shape, with or without tough polyethylene coatings, with or without wire brushes. Turbo pigs are available with a series of disks, cups, or wipers that each do a specific job. You can buy spheres, or you can purchase a mandrel that allows you to stack the equipment that makes sense to a particular job. There are pigs with instrumentation to evaluate pipe condition (called smart pigs). Different goals point you to different equipment.
One lesson that must be relearned every couple of years is that spheres require that the fluid behind them be similar in density to the fluid in front of them—they are a good choice to put between two different hydrocarbon liquids in a liquid pipeline, but are not effective with liquid on one side and gas on the other side.
Pig runs are initiated from “pig launchers” and terminate in “pig receivers.” These devices need to:
accept the pigs that are required to be run,
facilitate batch chemical treatment,
allow for disposal of the liquids that come in with the pigs,
Launchers fit into two categories: (1) gravity launch and (2) pressure launch. Gravity launchers operate by placing the pig in the device, sealing the chamber (called a “barrel”), and opening the chamber to the process pipeline and allowing the pig to fall down the inclined line into the flow. These devices are not terribly effective and it can take considerable time for the pig to actually fall into the flow.
Pressure launchers on the other hand require altering the flow path in the pipeline to place the flow behind the pig. There is a class of pressure launcher called a “pigging valve” that is very effective in many situations, and they will be discussed under “trunnion ball valves” later.
The launcher and receiver in Fig. 6.14 represent nearly 30 years of my evolution in designing pigging equipment. When I look at the equipment that I did on my first project I dearly want to “fix” it, but it works and I’m not going to apologize for designing this equipment based on designs in common use in the industry. As usual the “designs in common use” are the result of compromises between fabrication complexity, cost, and operability (with limited input from the operators), and are not as good as they could be. I’ve built upward of 20 launcher/receiver pairs to the exact design represented by Fig. 6.14 and it has been several years since I was last tempted to tweak it.
One of the most important learnings has been that there is no valid reason for a launcher to be significantly different from a receiver. I learned this lesson when our gas marketing department found a new market for our gas that required taking gas off the opposite end of the gathering system than we designed the system to provide. This required all launchers to become receivers and vice versa. Some of the auxiliary equipment was in awkward positions for the new functionality and required adaptations in processes, but it worked after a fashion. The current design would work well period.
We frequently have difficulty with terminology in communicating procedures and instructions between peers. It is worthwhile to describe the labeled items in Fig. 6.14.
Closure. The closure on a launcher or receiver should:
Operate reasonably quickly.
Have a pressure telltale as an integral part of the seal mechanism. This means that you cannot open the closure while the equipment is under pressure without there being a warning sound.
Be supported by hinges or davits that would prevent the closure from becoming a projectile in an opened-underpressure situation.
Be able to release pressure while still captured.
For many years all closures were “Huber-type” (lower image in Fig. 6.15) which have ears on the outer circumference that are intended to be hammered off and back on. These closures fail all of the criteria given in the previous list except for the first one. I have removed a Huber-type closure under pressure (the vent line plugged with paraffin after blowing down for 30 seconds) and it was very exciting—luckily I was standing out of the line of fire and when it finally opened it swung away from me instead of breaking my body.
The industry has largely transitioned away from hammer closures in favor of Yoke-type closures which have a tapered ring (the “yoke” in Fig. 6.15) that hold the door tightly against the flange. The two halves of the yoke are locked together with the yoke lock which is held in place with a “telltale” nut on a drilled stud which noisily releases any trapped gas when loosened. As the jacking bolts move the yoke halves apart, the door can come off the flange if there is still trapped pressure, but it is still captured by the yoke so it can’t swing. When the yoke is fully open the door can open. These closures satisfy all of the criteria given in the previous list.
Barrel. The barrel is the pipe between the closure and the eccentric reducer and it should:
Be one standard pipe size larger than the pipeline. Typically “the next pipe size” for 16 in (400 DN) pipe is 20 in (500 DN) since it can be difficult to find an 18×16 (450×400) eccentric reducer or an 18 in (450 DN) closure.
Be long enough. Barrel lengths have traditionally been fairly short (on the order of 5 ft 7 in (1700 mm) on a 20 in (500 DN) receiver) which limits the equipment that can be run. The minimum length for a 6 in (150 DN) launcher barrel should be 6 ft (1.83 m). For each pipe size above 6 in (150 DN) add 1 ft (0.3 m) (i.e., 8 in (200 DN) should be 7 ft (2.13 m), 20 in (500 DN) should be 12 ft (3.66 m), etc.).
Flange for extension spool. This flange on the barrel is an insurance policy against ever needing to run a very long pig. Regulations have begun to require periodic pipeline inspections using smart pigs. Smart pigs can be very long depending on how many evaluations are ongoing concurrently. Many operators are having to cut up launcher/receiver barrels to add piping to accommodate the long pigs, and then in many cases the longer barrel is in the way of normal traffic. Note in Fig. 6.14 that there is nothing connected between the closure and this flange. Having this flange on the barrel allows you to drop in a spool piece of any length without welding or disconnecting any piping.
Eccentric reducer. Use an eccentric reducer (with the flat side down) between the barrel and the throat to facilitate shoving the pig into the throat (with a concentric reducer or an eccentric reducer with the flat side up it can be very difficult to get a heavy pig to engage in the throat).
Throat. The throat is the same size as the pipeline. When loading a pig you try to engage the pig into the throat to seal the throat so that kicker gas will not bypass the pig. The throat should be at least twice as long as the maintenance pigs that you plan to run.
Pig signal. These devices (also called “pig indicator”) are used to inform the operator that a pig has passed. They can be intrusive (i.e., an arm reaches into pipe and a pig passing trips the arm) or nonintrusive (i.e., they have the ability to sense the pig passage from the outside of the pipe). They can be unidirectional (less expensive, but will break if you run a pig through backward, rarely a good investment) or bidirectional. Mechanical or electronic. This technology is changing rapidly and prior to deciding on a device you need to see what is currently available. A pig signal should be located to indicate that the pig has passed the barrel-isolation valve. For launchers this is on the barred tee. For receivers it is in the throat. Since we need to plan for someone requiring a change in flow direction, it is prudent to either use a nonintrusive pig signal or to use 4 pig signals for a launcher/receiver pair.
Process valves. All of the process valves should be full-port, trunnion ball valves (see later for valve descriptions). The valves we are concerned with are as follows:
Barrel-isolation valve. A normally shut valve that is the same size as the pipeline.
Side valve. A normally open valve that is the same size as the pipeline (this valve can be reduced port if there is a valid reason, but I don’t do it).
Kicker/bypass valve. Both valves should be sized to provide less than 0.13 psi/ft (2.9 kPa/m) at 100 psig (690 kPag) using Table 6.6. The location for source/return gas has evolved over time. I have found that with the current location I can build the entire launcher/receiver in a shop and ship it bolted together which has resulted in cost savings. The kicker/bypass line should tie into the barrel about one barrel diameter away from the flange for extension spool.
Table 6.6. Kicker line size
4 in (100 DN)
2 (50 DN)
16 (400 DN)
6 (150 DN)
6 in (150 DN)
3 (150 DN)
18 (450 DN)
6 (150 DN)
8 in (200 DN)
4 (100 DN)
20 (500 DN)
8 (200 DN)
10 in (250 DN)
4 (100 DN)
24 (600 DN)
8 (200 DN)
12 in (300 DN)
6 (150 DN)
30 (750 DN)
10 (250 DN)
14 in (350 DN)
6 (150 DN)
36 (900 DN)
10 (250 DN)
Barred tee. This tee needs to have pigging bars to make sure that you don’t lose control of the pig.
PSV. This safety valve is required by many jurisdictions, and it is a really good idea. It is possible (though not a good practice) to isolate the launcher/receiver barrel full of liquid. In that eventuality any increase in temperature will overpressure the barrel. Even if the barrel is just isolated and drained, it doesn’t take much of a leaking valve to put gas into the isolated barrel and in gas gathering systems that gas will be saturated with water vapor. A launcher that is opened once a quarter will always have some amount of liquid in it they are occasionally full. A very small thermal relief will prevent this liquid accumulation from damaging piping and/or valves.
Chemical injection port. I put a 1 in (25 DN) valve on the sweep on the pipeline side of the barrel-isolation valve to put chemicals directly into the line in front of a pig. My issues with the ineffectiveness of most chemicals are based on the inability of a flowing gas stream to keep them mobile and transport them through the system. A pig can accomplish this task quite effectively and facilitating their use is prudent. One chemical that I have had good success with is called a “gel pig” which is a fluid polymer that can be pumped into a line and then chased with a pig. The polymer tends to do a great job of aggregating scale, sludge, and slime into its matrix and can significantly improve the function of a line clogged with solids. The chemical injection port makes this evolution much easier. I put a chemical injection port on the receiver as well, but this valve is only there in case the line needs to change directions (or you need to run a pig backward to enhance cleaning).
Vents/drains. I put the barrel vent very close to the barrel-isolation valve. This location was selected in response to several leaking barrel-isolation valves one after the other. When the barrel-isolation valve has a small leak, the launcher is still usable, but when you seal the throat with the pig the leaking gas will spit it out of the throat before you have the closure shut, then opening the kicker valve will just bypass the pig. One inventive operator cut the handle off of a shovel and braced the handle between the pig and the closure, this allowed the pig to launch, but the stick had penetrated the pig and became the pig’s “tail” on the cleaning run. When it arrived, the tail prevented the receiver barrel-isolation valve from closing and the line had to be blown down to remove the pig.
There is also a vent on the spool between the “flange for extension spool” and the closure. That never gets used on the launcher. On the receiver it is used to shift the pig out of the throat for retrieval (using the other vent will stall the pig in the throat and it may not be possible to extract it without opening the barrel-isolation valve with the closure open, a practice that should be discouraged).
I put a drain on both launchers and receivers. On receivers the drain is piped to some disposal container that can hold the liquid from the pig run. On launchers I generally build a small containment area to drain condensation. Some operators leave this drain open between pig runs which adds to the surface corrosion inside the barrel and throat, but only minimally and has not been a problem.
Sweeps. Long pigs can have difficulty traversing a “long radius 45-degree elbow” which is the proper designation of the most common fitting used in gathering piping. By “long radius” ASME B16.7: Factory-Made Wrought Buttwelding Fittings means that the radius of the bend at the centerline of the pipe is 3 times the outside diameter of the pipe. For launchers and receivers it is better to use a “hot bend” which is a length of pipe that has been heated and bent to a specific bend radius. The most common bend radius specified for launchers and receivers is 6D, but I have seen 9D specified, the bigger the radius, the longer the pig that will traverse it. When smart pigs first came into the industry it was common for smart pigs to require 42D bend radius, but that excluded virtually all pipelines from using these tools. The technology has evolved and now most can pass a long-radius fitting, and all can pass a 6D sweep. When specifying the fabrication of hot bends (also called “induction bends” or “sweeps”), it is important to specify a minimum tangent length. The bend starts with a length of pipe (e.g., a 12 in (300 DN) pipe would have 60 in (152.4 mm) included a 6D 45-degree bend, the fabricator will start with a pipe a bit longer if you don’t specify a tangent), no matter how careful the fabricator is there will be some amount of ovality in the bent pipe, welding this out-of-round pipe to straight pipe can be very difficult and will frequently cause the weld to fail inspection. Adding pipe to the bend solves this. I always specify a minimum of 18 in (457 mm) tangents. It is common to get one tangent, i.e., 15 in (381 mm) and the other 21 in (533 mm), but both will be round pipe.
Design of product contact surfaces needs to take the following into account: surface texture, cleaning and inspection, disinfection, pasteurization and sterilization, microbial ingress, draining, dead spaces, joints, coatings, internal angles, corners and grooves, seals, gaskets, o-rings and joint rings, fasteners, process flow disruption caused by intrusions, shafts and bearings, sensor and sensor connections, other connections, and openings and covers.
Surface texture: Cracks, pits, and folds are to be avoided and the surfaces should be smooth.
Cleaning and inspection: All equipment must be cleanable either in or out of place and where possible the surfaces should be capable of inspection after cleaning.
Disinfection, pasteurization, and sterilization: It should be possible after cleaning to disinfect, pasteurize, or sterilize product contact surfaces either in place or after disassembly.
Microbial ingress: Where necessary, equipment should be designed to prevent ingress of microorganisms.
Draining: Pipelines and equipment should be completely drainable. This generally requires the use of eccentric reducers in horizontal pipe runs. It also necessitates that certain positive displacement pumps be mounted with their inlets and outlets in the vertical.
Dead spaces: Dead spaces in pipelines and equipment should be avoided. In particular tee pieces for positioning of instruments should be kept as short as possible.
Joints: Permanent metal-to-metal joints should be fully welded. Nonpermanent (dismountable) joints should be flush. Screw threads should not be present in the product contact area as these cannot be easily cleaned.
Coatings: Generally, coatings should be avoided in product contact areas. Where coatings cannot be avoided, they should be nonflaking and smooth.
Internal angles, corners, and grooves: Sharp corners within machinery are difficult to clean. For this reason, all corners should be radiused. In general, grooves, where used, should be wider than their depth.
Seals, gaskets, o-rings, and joint rings: Elastomers have higher coefficients of expansion than steels. This should be taken into account in design. Repeated heating and cooling can otherwise result in sections of the elastomer breaking off in the product. Furthermore, product may be sucked in and trapped behind the seal during cooling.
Fasteners: Fasteners such as screws, bolts, and rivets should be avoided within product areas. During disassembly, some external screw threads may come into contact with product. These should be designed to be cleanable.
Intrusions: In certain instances intrusions such as springs cannot be avoided within the product contact area. If such intrusions cannot be avoided, they should be cleanable.
Shafts and bearings: Shaft entry points require the use of mechanical seals. Where possible, there should be movement of fluid in the seal area. There should be an air gap between the product area and any lubricated bearings.
Sensor and sensor connections: They should be installed in such a way that there are no dead spaces or crevices.
Other connections: All permanent and nonpermanent pipework connections to equipment should be designed to prevent ingress of contamination.
Openings and covers: Hinges that allow crevices for soil to accumulate should be avoided.
Next to the selection of operating speeds, proper piping design is the most important consideration in pump installation design. Poor piping is often the result of inattention to details which can lead to
more than average down time
higher maintenance costs
loss of operating personnel confidence
Fig. 4.50 illustrates some of the following recommended installation guidelines for reciprocating pumps.
126.96.36.199 Suction piping
It is critical that the suction piping be sized to assure the NPSHA exceeds the NPSHR by the pump. Often, this can be arranged by elevating the suction tank or by providing a low-head centrifugal charge pump to feed the reciprocating pump. If the NPSHA is too low, valve breakage and pump maintenance costs will be excessive.
The pump inlet size has no bearing on the required suction piping size. The available suction head and the suction requirement and losses must be considered and piping sized on this basis, regardless of the pump size.
Both the suction and discharge piping should be
free of bends, if possible
minimum number of elbows and fittings
avoid piping high points where vapors can become trapped
elevation and plan changes should be laid out using 45° ells rather than 90° ells (if 90° ells are used, they should be long radius type)
suction pipe diameter changes should be made with eccentric reducers, with flat side up (FSU) to eliminate gas pockets
at least one nominal pipe size larger than the pump suction
to allow pump isolation, a full opening block valve should be installed in the suction piping
The suction piping should include a strainer and a pulsation dampener, if required. The suction strainer should not be installed unless regular maintenance can be assured. A fluid starved condition, resulting from a plugged strainer, can cause more damage to the pump than solids ingestion.
The suction supply vessel outlet should be slightly higher than the pump inlet so that gases accumulating in the system may flow back to the vessel rather than through the pump. The supply vessel should have sufficient retention time for the evolution of “free” gas. The suction and bypass lines should enter the supply vessel below the minimum fluid level. A vortex breaker should be installed on the outlet of the supply vessel.
Table 4.19 lists some suggested maximum flow velocities for sizing suction and discharge piping for reciprocating pumps. The piping should be large enough so that the velocity limits are not exceeded. A low flow velocity for the suction piping is particularly important. Some companies use a maximum velocity of 1 ft/s (0.3 m/s) regardless of pump speed.
Table 4.19. Maximum suction and discharge pipe velocities for reciprocating pumps
Pump speed, rpm
Suction velocity, ft/s (m/s)
Discharge velocity, ft/s (m/s)
When two or more pumps are installed in parallel, each pump's suction line between the tank and the pump should be piped separately (rather than in common) to preclude mutually reinforced pulsations. In most cases, however, this procedure is not practical, and the suction lines are often manifold together. If manifold together, the lines should be sized so that the velocity in the common feed line is approximately equal to the velocities in the lateral lines feeding the individual pumps. This avoids abrupt velocity changes and minimizes acceleration head effects. (The acceleration head requirement for multiple pumps on a common suction line is not the sum of single pump requirements; it increases approximately by the square of the number of pumps. For example, 3 pumps operating on a common suction line require approximately nine times the acceleration head (HA) of a single pump.)
188.8.131.52 Discharge piping
Just as fluid flows to a reciprocating pump in a pulsating flow pattern, it is discharged in the same manner. It has been shown that these pressure surges travel through the fluid in a straight line and are reflected back toward the source by restrictions or bends in the system. Also, when two or more pumps are discharging into a common header, these pressure surges may be amplified, causing damage to the pumps and piping. When designing a discharge piping system for reciprocating pumps:
Avoid sharp bends, reducers, valves with less than full opening, and so on, near the pump; these may reflect pressure surges back toward the pump.
Manifolds in which two or more pumps are tied into a common system should be located as far from the pumps as practical to allow dampening of surges. For most applications, 100 to 150 ft. (30 to 45 m) is adequate.
Discharge piping should be securely anchored as near the pump as practical to prevent system vibrations from acting directly on the pump.
Concentric reducers may be used, but they should be placed as near to the pump as practical.
Pressure safety valves (PSVs) should be installed in the discharge piping near the pump and certainly upstream of the first block valve. Discharge/outlet piping should have a high enough pressure rating for potential future needs. Consideration must also be given to discharge PSVs flange ratings. PSVs must be set high enough to avoid inadvertent discharges.
Directional piping changes should be made with 90° long radius ells.
Pipe diameters should be based on the maximum velocities recommended in Table 4.19. Common practice is to size discharge pipe one nominal pipe size larger than the pump discharge connection.
To facilitate priming and starting the following should be installed: Recycle (bypass) piped back to suction vessel, check valve, and block valve.
If a pulsation dampener is not included in the initial installation, a flanged connection should be provided should pulsation attenuation be required in the future.
184.108.40.206 Piping hook-up considerations
Fig. 4.51 shows an example hook-up for two reciprocating pumps operating in parallel. Since the pump can be accidently started when the discharge block valve is closed, a PSV is installed in the discharge line to keep the pump from overpressuring the pipe and flanges. The PSV should be installed downstream of the pulsation dampener. It is also possible to leave the suction valve closed while the discharge valve is opened. Discharge fluid could leak through the discharge FSV and pump valves, pressuring up the suction piping, which is rated for ASME 150 Class. Thus, in this installation, a PSV was installed in the pump suction piping. Some companies believe a suction PSV is unnecessary because of the low probability of multiple failures.
An appendage dampener and cone strainer are installed in the suction line. An inline bladder/desurger and FSV are installed in the discharge line. The FSV protects against leakage from discharge when the pump is not running. It is preferable that this be a piston FSV to keep it from chattering due to pressure pulsations. Nevertheless, swing FSVs are used successfully in some installations that follow the design practices for minimizing pulsations. Drain valves are provided so that the pump can be maintained easily, and an oil PSL is provided to shut-in the motor.
API RP 14C requires a PSH be installed on the discharge so that the pump will shutdown before the discharge PSV opens. It also requires that a PSL sensor on the discharge be installed to shutdown the pump in case of a large leak in the discharge piping. These two functions are carried out by one device.
18.5 Cooling by Spraying Fog or Flowing Water over Top of the Concrete Block
18.5.1 Spraying Fog over Top of the Concrete Block
When pouring concrete in summer, it is better to form a foggy insulating layer over the top of the concrete block by spraying fog. This could reduce the direct sunlight so as to lower the surface temperature of the concrete block.
There are arc sprayer, straight tube sprayer, T-shaped sprayer, and axial flow fan sprayer. The former two can be used in large concrete block, and the latter two are suitable for small concrete blocks. The performances of these four kinds of sprayers are shown in Table 18.2.
Table 18.2. Comparison of Performance of Four Kinds of Sprayers
Axial Flow Fan Sprayer
Direct use of energy
Pressure water, wind
Pressure water, wind
Pressure water, wind
Performances of spray
The fog is dense and the effect of fogging is good, the fogging range is large
The fogging range is large, while the effect of fogging is common
The fogging range is small, and the effect of fogging is common. More sprayers should be placed in one block
The fogging range is small, and the effect of fogging is common. More sprayers should be placed in one block
Covering range (m)
Cooling effect (°C)
In order to improve the effect of spraying, a fog-spray device was successfully developed and used in the Three Gorges stage II Project. Pressure swirl atomizer atomizes the water into fine droplets, which were then blown onto the surface of the concrete uniformly and formed a fog layer. On one side, the fog droplets would evaporate by absorbing heat; on the other side, the fog layer could reduce the direct sunlight, thereby reducing temperature of the pouring surface. Its working process is as follows.
The pressure water gets into the combined atomizing nozzle through the control valve, the pressure gauge and the filter, and then formed into micro droplets, of which the diameter ranges from 40 to 100 μm. The control valve can adjust the water pressure within 0.3–0.6 MPa, in order to control the atomizing. Oblique flow high-pressure blower generates high-pressure conveying flow, which sends the droplets into the distance. The swinging system, consisting of a low-speed motor, worm gear reducer, eccentric wheel, swing link, and a bracket, drives the fan to reciprocating swing of 3–4 times/minute within 0–90°. The elevation angle bracket installed under the fan, according to the environmental condition, can upgrade the fan within 0–20°.
The fog-spray device comprises atomizing system, conveying flow system, and swinging system and the base, etc. The base is equipped with a solid caster and can be pushed on the surface and change the spray direction. The base bench was welded by angle steel, with steel plate covered to the external, and can be removed for inspection and maintenance of the swing system in the base box.
The effect of the fog-spray device used in the Three Gorges Project is as follows. (1) The temperature of the concrete is lower than the environment, after the spraying. The temperature can be cooled by 6–10°C within 9–12 m, and 2–3°C with 18.0 m from the nozzle. (2) The cooling effect of the fog-spray device without elevation angle, the elevation angle is 0°, is better than that with some elevation angle. (3) The spraying effect has something to do with the wind direction and wind speed, and when spraying along wind, the cooling effect is best, and also the area of coverage is large. (4) In order to understand the spraying effect on concrete, two 100 mL measuring cylinders are respectively placed 6 and 9 m from the nozzle, and 1 h later the cylinder is checked to see if there were any water drops. This would not affect the quality of the concrete. (5) The experiments show that, although the spraying effect and environmental temperature have certain relations, the atomizing effect on cooling extent of the surface temperature is basically the same. (6) The spraying effect is related to the head pressure, the larger the water pressure, the better the atomizing cooling effect, but the atomizing effect changes a little with continued increase of the water pressure. The test results show that the atomizing effect is good, and the water consumption is small when the water pressure is about 0.6 MPa.
18.5.2 Cooling by Flowing Water over Top of the Concrete Block
In the construction of Toktogul dam in the former Soviet Union, the flowing water is adopted fully to cool the concrete. The flow of water starts immediately after the final set of concrete and the clearance of laitance of the surface, no more than 12 h after pouring the concrete. The water comes from small holes drilled in the pipe and forms a flow layer with thickness 2–8 mm on the surface of the concrete and the flow velocity is less than 0.8 m/s. It is not allowed to interrupt the flowing of water when the temperature is higher than 20°C. The temperature of the flowing water in the pipe is no more than 18°C and that over the top of the concrete is no more than 19°C. In the hot months of July and August, the flowing water over the top of the concrete is 13.5 L/s in each of the 1000 m2 areas; in June and September, the flow can be reduced to 25%. The average flow for each 1000 m2 of 8 h in every day is 8 L/s in April, May, and October. The measured water temperature would increase 1°C–3°C in practice. To insure the effect of flowing water, the concrete should be poured in thin layers. The layer thickness of the Toktogul dam is 0.5–1.0 m, and due to the flowing water, the temperature heat rises only 3–5°C due to hydration heat in the hottest month every year. The cooling water can be derived from the drilling holes or the drainage sump.
The calculation of the cooling effect of flowing water over the surface is simple: calculate the concrete lift according to the first kind of boundary condition and let the surface temperature equal to the water temperature.
Steam lines should ideally be arranged to fall in the direction of flow, at not less than 100 mm per 10 m of pipe (1:100). This slope will ensure that gravity (and the flow of steam), will assist in moving the condensate towards drain points so that the condensate may be safely and effectively removed (see Fig. 15.4). Any steam lines rising in the direction of flow should slope at not less than 250 mm per 10 m of pipe (1:40).
Steam lines should be fitted with drains at regular intervals of 30–50 m and at any low points in the system. Where drainage has to be provided in straight lengths of pipe, a large bore pocket should be used to collect condensate. If strainers are to be fitted, then they should be fitted on their sides.
There are, however, many occasions when a steam main must run across rising ground, or applications where the contours of the site make it impractical to lay the pipe with the 1:100 fall proposed earlier. In these situations, the condensate must be encouraged to run downhill and against the steam flow. Good practice is to size the pipe on a low steam velocity of not more than 15 m s−1, to run the line at a slope of no less than 1:40, and install the drain points at not more than 15 m intervals (see Fig. 15.5). The objective is to prevent the condensate film on the bottom of the pipe increasing in thickness to the point where droplets can be picked up by the steam flow.
15.9.2 Drain Points and Condensate Removal
Drain points must be designed to ensure that the condensate can reach the steam trap. Careful consideration must therefore be given to the design and location of drain points.
Consideration must also be given to the condensate remaining in a steam main at shutdown, when steam flow ceases. Gravity will cause condensate to run along sloping pipework and collect at low points in the system. Steam traps should therefore be fitted to these low points.
The amount of condensate formed in a large steam main under start-up conditions is sufficient to require the provision of drain points at intervals of 30–50 m, as well as natural low points such as at the bottom of rising pipework.
In normal operation, steam may flow along the main at speeds of up to 432 km h−1, entraining condensate. Fig. 15.6 shows a 15 mm drain pipe connected directly to the bottom of a main. Although the 15 mm pipe has sufficient capacity, it is unlikely to capture much of the condensate moving along the main at high speed, so this arrangement will be ineffective.
A more reliable solution for the removal of condensate is shown in Fig. 15.7. The trap line should be at least 25–30 mm from the bottom of the pocket for steam mains up to 100 mm, and at least 50 mm for larger mains. This allows a space below for any dirt and scale to settle. The bottom of the pocket may be fitted with a removable flange or blowdown valve for cleaning purposes.
Recommended drain pocket dimensions are shown in Table 15.1 and in Fig. 15.8.
Table 15.1. Recommended Drain Pocket Dimensions
Up to 100 mm NB
d1 = D
Minimum d2 = 100 mm
125–200 mm NB
d1 = 100 mm
Minimum d2 = 150 mm
250 mm and above
d1 ≥ D/2
Minimum d2 = D
Source: Spirax Sarco.
Traps selected should be robust enough to avoid water hammer damage and frost damage. Water hammer is a pressure surge caused by slugs of liquid (often condensate) colliding at high velocity with pipework fittings, plant, and equipment (Fig. 15.9). This has a number of implications:
Because the liquid velocity in the surge is higher than normal, the dissipation of kinetic energy is higher than would normally be expected
Water is dense and incompressible, so it has high momentum, and the “cushioning” effect experienced when gases encounter obstructions is absent
The energy in the water is dissipated against the obstructions in the piping system such as valves and fittings.
Indications of water hammer include banging noises and pipe movement. In severe cases, water hammer may fracture pipeline equipment with almost explosive effect, with consequent loss of live steam at the fracture, leading to an extremely hazardous situation.
Good engineering design, installation, and maintenance will avoid water hammer. Avoidance by design is far better practice than attempting to contain it by choice of materials and pressure ratings of equipment. Commonly, sources of water hammer occur at the low points in the pipework (see Fig. 15.10).
Such areas are due to:
Sagging in the line, perhaps due to failure of supports
Incorrect use of concentric reducers (see Fig. 15.11)—always use eccentric reducers with the flat at the bottom on steam lines
Incorrect strainer installation—these should be fitted with the basket on the side
Inadequate drainage of steam lines
Incorrect operation—opening valves too quickly at start-up when pipes are cold
15.9.3 Steam Branch Lines
Branch lines (Fig. 15.12) are normally much shorter than steam mains. As a general rule, therefore, provided the branch line is not more than 10 m in length, and the pressure in the main is adequate, it is possible to size the pipe on a velocity of 25–40 m s−1, and not to worry about the pressure drop.
Branch line connections taken from the top of the main carry the driest steam (Fig. 15.27). If connections are taken from the side, or even worse from the bottom (as in Fig. 15.13A), they can accept the condensate and debris from the steam main. The result is very wet and dirty steam reaching the equipment, which will affect performance in both the short and long term.
The valve in Fig. 15.13B should be positioned as near to the off-take as possible to minimize condensate lying in the branch line when the plant is shut down for an extended period.
Low points will also occur in branch lines. The most common is a drop leg close to an isolating valve or a control valve (Fig. 15.14). Condensate can accumulate on the upstream side of the closed valve, and then be propelled forward with the steam when the valve opens again—consequently a drain point with a steam trap set is good practice just prior to the strainer and control valve. There will usually be another isolation valve close to the end user/equipment for equipment isolation.
15.9.4 Steam Separators
Modern packaged steam boilers have a large evaporating capacity for their size and have limited capacity to cope with rapidly changing loads. In addition, other circumstances such as incorrect chemical feed water treatment and/or TDS control, and/or transient peak loads in other parts of the plant can cause priming and carryover of boiler water into the steam mains. Separators, as shown by the cut section in Fig. 15.15, may be installed to remove this water. Separators should also be considered before any piece of steam using equipment ensuring that dry steam is used.
As a general rule, providing the velocities in the pipework are within reasonable limits, separators will be line sized. A separator will remove both droplets of water from pipe walls and suspended mist entrained in the steam itself. Water hammer can be eradicated by fitting a separator in a steam main, which can often be less expensive than increasing the pipe size and fabricating drain pockets.
A separator is recommended before control valves and flowmeters. It is also wise to fit a separator where a steam main enters a building from outside. This will ensure that any condensate produced in the external distribution system is removed and the building always receives dry steam. This is especially important where steam usage in the building is monitored and charged for.
220.127.116.11 Steam Strainers
When new pipework is installed, it is not uncommon for fragments of casting sand, packing, jointing, swarf, welding rods and even nuts and bolts to be accidentally deposited inside the pipe. In the case of older pipework, there will be rust and, in hard water districts, a carbonate deposit.
Occasionally, pieces will break loose and pass along the pipework with the steam to rest inside a piece of steam using equipment. This may, e.g., prevent a valve from opening/closing correctly. Steam using equipment may also suffer permanent damage through wiredrawing—the cutting action of high velocity steam and water passing through a partly open valve. Once wiredrawing has occurred, the valve will never give a tight shut-off, even if the dirt is removed.
It is therefore best (but not universal) practice to fit a line-size strainer in front of every steam trap, flowmeter, reducing valve and regulating valve. The illustration shown in Fig. 15.16 shows a cut section through a typical strainer.
Steam flows from the inlet “A” through the perforated screen “B” to the outlet “C.” While steam and water will pass readily through the screen, dirt cannot. The cap “D” can be removed, allowing the screen to be withdrawn and cleaned at regular intervals. A blowdown valve can also be fitted to cap “D” to facilitate regular cleaning.
Strainers can, however, be a source of wet steam, as previously mentioned. To avoid this situation, strainers should always be installed in steam lines with their baskets to the side.
18.104.22.168 Steam Traps
Steam traps are the most effective and efficient method of draining condensate from a steam distribution system. The steam traps selected must suit the system in terms of pressure rating, capacity, and suitability.
Pressure rating is easily dealt with; the maximum possible working pressure at the steam trap will either be known or should be established.
The capacity (quantity of condensate to be discharged) can be divided into two categories; warmup load and running load. For warmup load, in the first instance the pipework needs to be brought up to operating temperature. The condensate load form this activity can be determined by calculation, knowing the initial temperature, mass and specific heat capacity of the pipework and fittings.
The initial pressure in the main will be little more than atmospheric when the warmup process begins. However, the condensate loads will still generally be well within the capacity of a DN15 “low capacity” steam trap. Only in rare applications at very high pressures (above 70 barg) combined with large pipe sizes, will greater trap capacity be needed.
For running load, once the steam main is up to operating temperature, the rate of condensate production is mainly a function of the pipe size and the quality and thickness of the insulation.
Steam trap types used to drain condensate from mains are shown in Fig. 15.17. The thermostatic trap is included because it is ideal where there is no choice but to discharge condensate into a flooded return pipe.
The layout of condensate pipework is complex. Much depends on the application pressure, the steam trap characteristics, the position of the condensate return main relative to the plant, and the pressure in the condensate return main. For this reason, it is best to start by considering what has to be achieved, and to design a layout that will ensure that basic good practice is met.
The prime objectives are that:
Condensate must not be allowed to accumulate in the plant unless the steam-using equipment is specifically designed to operate in this way. As equipment is not usually designed in this way, condensate accumulation generally inhibits performance, and encourages corrosion.
Condensate must not be allowed to accumulate in the steam main, where it can be picked up by high velocity steam, leading to erosion and water hammer in the pipework.
There are four types of condensate line from a layout designer’s point of view. These four types are defined and illustrated in Fig. 15.18.
In a drain line, condensate and any incondensable gases flow from the drain outlet of the plant to the steam trap. In a properly sized drain line, the plant being drained and the body of the steam trap are virtually at the same pressure and, because of this, condensate does not flash in this line.
Gravity is relied upon to induce flow along the pipe. For this reason, it makes sense for the trap to be situated below the outlet of the plant being drained, and the trap discharge pipe to terminate below the trap (an exception to this is tank-heating coils).
The type of steam trap used (thermostatic, thermodynamic, or mechanical) can affect the piping layout. It is usually easier and cheaper to select the correct trap for the job, than have the wrong type of trap and fabricate a solution around it.
The drain line should be kept to a minimum length, ideally less than 2 m. Long drain lines from the plant to the steam trap can fill with steam and prevent condensate reaching the trap. This effect is termed steam locking. To minimize this risk, drain lines should be kept short (see Fig. 15.19). In situations where long drain lines are unavoidable, the steam locking problem may be overcome using float traps with steam lock release devices. The problem of steam locking should be tackled by fitting the correct length of pipe in the first place, if possible.
The detailed arrangements for trapping steam-using plant and steam mains drainage differ.
With steam-using plant, the pipe from the condensate connection should fall vertically for about 10 pipe diameters to the steam trap. Assuming a correctly sized ball float trap is installed, this will ensure that surges of condensate do not accumulate in the bottom of the plant with its attendant risks of corrosion and water hammer. It will also provide a small amount of static head to help remove condensate during start-up when the steam pressure might be very low. The pipework should then run horizontally, with a fall in the direction of flow to ensure that condensate flows freely (see Fig. 15.20).
With steam mains drainage, provided drain pockets are installed, the drain line between the pocket and the steam trap may be horizontal. If the drain pocket is not as deep as the recommendation, then the steam trap should be fitted an equivalent distance below it (see Fig. 15.21).
Discharge lines from traps carry condensate, incondensable gases, and flash steam from the trap to the condensate return system (Fig. 15.22). Flash steam is formed as the condensate is discharged from the high-pressure space before the steam trap to the lower pressure space of the condensate return system.
These lines should fall in the direction of flow to maintain free flow of condensate. On shorter lines, the fall should be discernible by sight. On longer lines, the fall should be about 1:70, i.e., 100 mm every 7 m.
Discharging traps into flooded return lines is not recommended, especially with blast action traps (thermodynamic or inverted bucket types), which remove condensate at saturation temperature.
Good examples of flooded condensate mains are pumped return lines and rising condensate lines. They often follow the same route as steam lines, and it is tempting to simply connect mains drainage steam trap discharge lines into them. However, the high volume of flash steam released into long flooded lines will violently push the water along the pipe, causing water hammer, noise and, in time, mechanical failure of the pipe.
Where condensate from more than one trap flows to the same collecting point such as a vented receiver, it is usual to run a common line into which individual trap discharge lines are connected. Provided the layouts as featured in Figs. 15.23–15.25 and 15.27 are observed, and the pipework is adequately sized, this is not a problem.
If blast discharge traps (thermodynamic or inverted bucket types) are used, reaction forces and velocities can be high. Swept tees will help to reduce mechanical stress and erosion at the point where the discharge line joins the common return line (see Fig. 15.23).
If, for some reason, swept tees cannot be used, a float-thermostatic trap with its continuous discharge action is a better option (Fig. 15.24). The flooded line will absorb the dissipated energy from the (relatively small) continuous flow from the float-thermostatic trap more easily.
If the pressure difference between the steam and condensate mains is very high, then a diffuser will help to cushion the discharge, reducing both erosion and noise.
Another alternative is to use a thermostatic trap that holds back condensate until it cools below the steam saturation temperature to reduce the amount of flash steam formed (Fig. 15.25). To avoid waterlogging the steam main, the use of a generous collecting pocket on the main, plus a cooling leg of 2–3 m of unlagged pipe to the trap is essential. The cooling leg stores condensate while it is cooling to the discharge temperature.
If there is any danger of waterlogging the steam main, thermostatic traps should not be used.
Processes using temperature control provide an example where the supply steam pressure is throttled across a control valve. The effect of this is to reduce steam trap capacity to a point where the condensate flow can stop completely, and the system is said to have stalled.
Stall occurs as a result of insufficient steam pressure to purge the steam plant of condensate, and is more likely when the plant has a high turndown from full-load to part load.
Not all temperature-controlled systems will stall, but the backpressure caused by the condensate system could have an adverse effect on the performance of the trap. This in turn, might impair the heat transfer capability of the process (Fig. 15.26).
Condensate drain lines should therefore be configured so that condensate cannot flood the main into which they are draining, as depicted in Fig. 15.27.
Condensate from more than one temperature controlled process may join a common line, as long as this line is designed to slope in the direction of flow to a collection point, and sized to cater for the cumulative effects of any flash steam from each of the branch lines at full load.
The concept of connecting the discharges from traps at different pressures is sometimes misunderstood. If the branch lines and the common line are correctly sized, the pressures downstream of each trap will be virtually the same. However, if these lines are undersized, the flow of condensate and flash steam will be restricted, due to a buildup of backpressure caused by an increased resistance to flow within the pipe. Condensate flowing from traps draining the lower pressure systems will tend to be the more restricted.
Each part of the discharge piping system should be sized to carry any flash steam present at acceptable steam velocities. The discharge from a high-pressure trap will not interfere with that from a low-pressure trap if the discharge lines and common line are properly sized and sloped in the direction of flow.
Flash steam may, at some point, be separated from the condensate and used in a recovery system, or simply vented to atmosphere from a suitable receiver (Fig. 15.28). The residual hot condensate from the latter can be pumped on to a suitable collecting tank such as a boiler feed tank. When the pump is served from a vented receiver, the pumped return line will be fully flooded with condensate at temperatures below 100°C, which means flash steam is less likely to occur in the line.
Flow in a pumped return line is intermittent, as the pump starts and stops according to its needs. The pump discharge rate will be higher than the rate at which condensate enters the pump. It is, therefore, the pump discharge rate which determines the size of the pump discharge line, and not the rate at which condensate enters the pump.