Process Engineering Manual 005 II

August 1, 2017 | Author: muktaanand | Category: Gas Compressor, Steam Engine, Pump, Engines, Transparent Materials
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Introduction To enable the procurement of a pump, it is necessary to convey to the vendor all pertinent process information. This process information is conveyed to the Specialist/Mechanical group of TPPL in the form of Process group's standard Pump Data Sheet. Based on this information, the Mechanical group prepares the pump specification sheet to be sent to the vendors. The pump calculation sheet helps the process engineer in assembling the required data in the pump data sheet. Following guidelines should be used in preparing pump data sheets.


Types of Pumps Pumps generally used in process industries are of centrifugal, reciprocating (piston, plunger or diaphgram type) or rotary (gear, screw, lobe or others) types. A proper selection of the type of pump to be used in a particular service has to be made.


Selection of Pump Type Except for special purpose pumps for specific services, most of the process pumps are made in standard sizes, and hence, the main problem is to select the size and type that most nearly fits the service in question. Though the final selection of the pump will be made close cooperation between the vendor and the Mechanical group, a preliminary selection of the type of pump required is made by the process engineer. Selection of thc pump type can be made on the basis of capacity-head requirements or fluid properties e.g. viscosity, solid content and corrosive or erosive nature. Use Figure 1.1 for pump type selection based on head-capacity requirements.

Centrifugal type pumps will handle liquids having viscosity up to about 200 cst. For higher viscosities, specify screw, gear or reciprocating types. If solids are present in the stream to be handled, the choice of pumps is further restricted. When solids are present, all internal passages should have adequate dimensions. If solids are abrasive, close internal tolerances between stationary and moving parts are undesirable. Generally, centrifugal type pump (especially open impeller type) is the choice for handling liquids present in them.


Fluid Properties

Properties of the fluid to be pumped require careful attention of the process engineer. The process engineer should give all the pertinent information asked for in the process data sheet regarding the fluid characteristics. When solids or abrasive material are present, specify the amount and size of particles. Similarly, if corrosive and toxic materials are involved, specify the exact nature and concentration. Specify the pour point, congealing point etc. accurately to determine the type of seal flush arrangement and any special jacketing or heating arrangement required.


Suction Conditions and NPSH Improper suction conditions are the largest source of pump troubles. Careful attention should be given to NPSH (Net positive suction head). NPSH is the net remaining pressure at the suction flange of the pump after all negative forces that restrict liquid from getting into the pump are subtracted from all the positive forces that assist liquid in getting into the pump. Two terms of NPSH are referred to:


Net Positive Suction Head available in the system expressed as meters of liquid.


Net Positive Suction Head required by the pump expressed as meters of liquid.

Calculate NPSHA in the system as follows:


Terminal Pressure in the Vessel + Height of Fluid above Pump Centre Line (see note) + Atmospheric Pressure – (Vapour Pressure of Liquid + Friction Loss in Suction Piping up to Pump Centre Line + Entrance and Exit Losses From Vessel + Loss in Suction Filter + Loss in Control Vale, Exhaner etc., if any)

Note : 1. The height of liquid in the vessel should be taken to be at the vessel bottom tangent line. 2. Pump centre line should be considered at 3/4 meter above the ground level.

Calculate NPSHA carefully considering all conditions i.e. start-up, original fill of lines, winter operation, all control valve pressure drops, summer operation, piping conditions, exit and entrance losses. Provide NPSHA at 1 meter over worse conceived NPSHR curve

by the manufacturer. In general, NPSHR of pumps should be considered as 3.0 meters, though the exact requirement will be specified by the pump manufacturer. In case of submersible pumps, the available submergence should be specified.

NPSH is a function of flow. It should, therfore, always be determined at design capacity regardless of the total head required. It. is not uncommon for NPSHR curve to turn upward at low flows. Low flow effects can often be amplified by selecting too large a pump which forces recirculation within the pump.

When liquids at their bubble points are pumped from closed vessels, NPSHA is only the static liquid head above the pump centre minus the friction losses in the suction piping. In such cases, it is usual to elevate the vessels suitably (or sometimes cool the liquid before it enters the pump) to get a margin of NPSHA over NPSHR. Sometimes, booster pumps (low head, high capacity pumps which require low NPSH) are used ahead of main line pumps to improve the NPSHA for the main pump which has high capacity high head requirements.


Pumping Capacity Proper care should be taken in establishing the rated capacity of the pump. Normal flow rate required by the process to be pumped should be estimated. A margin over this normal should be added to take care against pump runout, internal leakage/ slippage in the pump and contingencies. Following guidelines should be useful for specifying the capacity:

Type of Pump

% margin to be added to normal flow requirement

Centrifugal 3.

Single stage



Multi stage






Pumps should not be oversized beyond the above recommended margins. Operating at reduced capacities can result in increased bearing loads, reduction in pump efficiency and sometimes increased NPSH requirement. When a future capacity increase in anticipated, find out whether it can be accommodated by adding one more pump in future or using a new wide impeller instead of specifying the pump for the future requirements and running it at reduced flows now.


Discharge Conditions The suction pressure and discharge pressure at the pump suction and discharge flanges respectively should be estimated by drawing the system sketch in the pump calculation sheet. All pressure drops in the system should be considered for various conditions – start up, shutdown, fouled condition of piping/ equipment, start of run, end of run etc. The difference between the discharge pressure and suction pressure so calculated is the differential pressure or differential head when expressed in meters of liquid. The differential head required for different conditions should be estimated and specified in the pump process datasheet after taking about 10% margin over the normal differential head requirement.

A centrifugal pump will not produce a higher pressure than its shut-off pressure even if the discharge line is completely blocked. On the average, shut-off pressure is the maximum suction pressure plus 1.2 times the differential pressure depending on the characteristic curve of the pump. To avoid changes in the design at a later stage, the pump shut-off pressure should be considered as maximum suction pressure plus 1.25 times the differential pressure. All downstream equipment in the system e.g. piping, valves, exchangers, vessels etc. should be designed for this shut-off pressure. During detailed engineering, this shut-off pressure should be checked against the actual shut-off pressure specified by the vendor.


No. of Pumps and Sparing Philosophy

1.8.1 Pumps in Regular Use

Normally, only one pump is provided for regular use. In some cases, however, when pumping capacities are very large and a single pump is not available, more than one operating pump may be specified. Where substantial future capacity has to be catered for, it is advisable to put additional pump in future (for which space should be kept in the system) than to oversize the present pump.

1.8.2 Sparing Philosophy

A combination of factors including desired process reliability, service factor, service factor, operating conditions, customers maintenance philosophy and cost etc. should be considered to establish pump sparing philosophy. In general, 100% spare should be

provided for essential services and hot (above 200°C), high pressure, dirty, clogging and polymerising service. For clean fluids and non-essential services, 50% spares can be specified. If more than two pumps are running in parallel for the same service, a common standby pump can be specified. Sometimes a common spare can be provided for two compatible services.

Following criteria can be used for identifying the various service conditions : •

Essential Services ∼ Furnace and reactor charge pumps ∼ Product and reflux pumps

Non-essential Services ∼ Product transfer pumps ∼ Chemical and additive injection pumps ∼ Product blending and circulation pumps

Dirty/Clogging Services ∼ Pump feeding from tank bottoms ∼ Pumps taking suction from tower ∼ Bottoms slurry service

Pump Reliability ∼ Pumps having mechanical seals are generally more reliable than pumps with stuffing boxes. ∼ Rotary and positive displacement pumps are less reliable than centrifugal pumps.

1.8.3 Warm-up Connection for Standby Pumps

Standby pumps under hot services (temperature above 150°C) should be always kept heated up by providing a warm-up connection. Refer to Chapter 7 of Volume-IV of the Process Engineering Manual titled P&ID Development for typical sketches of these warmup connections.

1.8.4 Pumps Running in Parallel

If two identical pumps are simultaneously working in parallel, they will deliver the sum of the capacities to the same total head. The reasons for parallel pump operation can be:

1. Economy - two pumps and one standby can be more economical than one larger pump and a standby

2. Two or three flow rates

3. Flow rates too large for a single pump to handle

Some cooling water and fire water pumps are typical examples.


Characteristic Curves of Centrifugal Pumps Figure 1.2 is a typical characteristic curve of a centrifugal pump. The nature of head capacity curve, efficiency and NPSH curves can be different depending upon the type of pump. For a given system, the head-capacity curve of the system is superimposed on the head-capacity curve of the pump and the point of intersection of the two curves is the duty point at which the pump will operate at its best efficiency. The system head curve is a function of the system static head and pressure head which are constant and the friction head which varies with the flow.

Pump vendors will supply the characteristic curve for each pump. Following points should be considered while finally accepting the pump: • The slope of the head capacity curve should not be too steep if the pump delivers into a distribution system, since a small change in flow will cause a large change in delivery pressure. • The slope should not be too flat if the pump capacity is to be controlled by throttling discharge (manually or by a control valve). • When pumps are to run in parallel, the head-capacity curve should be stable i.e. a curve with the head constantly increasing as one approaches zero capacity. A dropping type curve (where the shut-off head is less than the maximum head) gives an unstable operation. This requirement is also valid for all pumps within battery limits having standby. • Manufacturers supply characteristic curves of pumps based on water as test fluid used in the testing shop. While handling viscous fluids in actual practice, certain corrections

need to be made for viscosity to get the actual head, capacity and efficiency. Use Figure 1.3 for correction charts for pumping viscous fluids.


Choice of Driver Electric motor is by far the most common drive for pumps in the process industry. Occasionally, special considerations such as reliability of power, safety considerations and criticality of service require turbine drives to be used. Sometimes, the plant utility balance makes turbine drives necessary on large pumps. Steam turbines are effective for standby pumps for a few larger, vital pumps such as charge pumps, cooling water pumps, unit pump out pumps or flushing out pumps. These considerations have to be firmed up during the design basis stage.

Steam turbines can be condensing or non-condensing type. The choice of non-condensing or condensing operation is affected by the demand for the exhaust steam. Generally, pump drives are not made condensing type without a rigorous review as the increased complexity or condensing is rarely worth the small savings achieved in the utilities.

In some cases like offshore platforms, oil and gas processing terminals etc., gas turbines are used as drivers for large pumps.


Utilities for Pumps All pumps will need some utilities – electrical power for motor driven pumps ; steam for steam-turbine driven pumps; cooling water for condensers of steam turbines; cooling water for bearings, casing pedestals and packing; steam for seal quench, jacketing etc. Though the exact requirements of different utilities needed by a pump will be specified by the pump vendor, it is essential for a process engineer to have a fairly good idea about these requirements so that they can be included in the utility summary sheet of the plant. These requirements can later be firmed up after getting the vendor information. Following guidelines can be used for estimating utilities required by the pump.

1.11.1 Power for Pump Driver

Compute the power consumption for the pump as shown in the pump calculation sheet. Refer Figures 1.4, 1.5 and 1.6 for efficiencies of different types of pumps and Table 1.1 for motor efficiencies. Take 120% of the power so computed for utility estimation.

1.11.2 Steam for Turbines

Steam requirements of a steam turbine can be estimated by using Figures 1.7 and 1.8. Following instructions apply for the use of these figures. 1. Compute the delivered horse power (BHP) as shown in the pump calculation sheet. 2. Determine turbine efficiency from table below : KW 150 From 151 – 500 From 501 – 2000 From 2001 – 6000 Above 6000

Overall Efficiency % 35 45 55 65 70

3. Determine steam rate from Figures 1.7 and 1.8. Table 1.1 : Electric Motors – Recommended Sizes and Efficiencies Pump Requirement at Probable Motor Motor Efficiency @ % of Full Design Conditions Rating Load 0 – 0.5 1 81 82 82.5 0.51 - 0.75 1.5 67 73 75 0.75 – 1.00 2 75 78 80 1.01 – 2.00 3 75 79 80 2.01 – 4.00 5 81 83 84 4.01 – 6.00 7.5 75 80 81.5 6.01 – 8.00 10 80 84 85 8.01 – 12.0 15 81 85 86.5 12.1 – 16.0 20 80 83 86 16.1 – 20.0 25 83 86.5 88 20.1 – 26.1 30 83 86.5 88.5 26.2 – 34.8 40 85 88 88.5 34.9 – 43.5 50 80 85 87.5 43.6 – 52.2 60 84 88 89.5 52.3 – 65.2 75 87 89.5 90.5 65.3 – 87.0 100 84 89 91 87.1 – 114 125 85 89.5 91.5 115 – 136 150 86 89 91 137 – 182 200 88 91 92.5 183 – 227 250 90 92.5 93.5 228 – 273 300 90.5 93 94 274 – 318 350 91 93 94 319 – 364 400 91 93 93 365 – 409 450 91 93 93 410 – 455 500 91.5 93 93.5 456 – 545 600 93 94 94.5 Note : This table applies to totally enclosed motors (i.e. explosion proof)

• For non-condensing turbines and inlet steam pressure up to 18.5 kg/cm2a use Figure 1.7. For all condensing turbines and non-condensing turbines with inlet system pressure up to 43.5 kg/cm2a, use Figure 1.8. • Determine heat theoretically available from saturated steam of the anticipated inlet and exhaust pressure from graph 1 of Figure 1.7. • Correct heat available for unsaturation or superheat as indicated on the figures. • Determine steam rate from efficiency and heat available by use of graph 2 of Figure 1.7. • Estimate steam requirements by multiplying the brake horse power and the steam rate calculated from Figures 1.7 and 1.8.

1.11.3 Cooling Water Pumps

Cooling water may be required for a pump for cooling its bearing, pedestral, gland packing, etc. This water can be fresh raw water, circulating cooling water or sea water. Generally, the water after cooling the various parts of the pumps is routed to drain. Use the following general guidelines for estimating water requirement for pump cooling :

Up to 120°C Up to 250°C Above 250°C

0.5 m3/hr 1.5 m3/hr 2.0 m3/hr

Some minor leakage of oil from the pump can be expected which will also be routed to drain along with the above water. Take about 200 ppm of oil content in the outlet water to drain for the purpose of effluent summary of the plant.

1.11.4 Steam for Quenching and Jacketing

Pumps handling high pour point products like Bitumen, LSHS, DMT, Phthalic Anhydride and other such products are often steam jacketed. Specify steam conditions available in the datasheet. The approximate requirement of steam for each such pump may be taken as 200 kg/hr.


Pump Sealing System Process data sheets for pumps should indicate the type of sealing to be provided. Use the following guidelines for selection of type of sealing:

Service Type of Sealing External Flushing Clean hydrocarbons and non-corrosive Single Mechanical Required chemicals which will not solidify at Seal ambient conditions at temperatures upto 300°C and pressure upto 40 kg/cm2a Clean liquids which will solidify at Single Mechanical Required ambient conditions, temperature upto Seal 300°C and pressures upto 40 kg/cm2a. Very corrosive, dirty or high pressure Double Mechanical Required service Seal Slurries

Packed Box

Not Applicable

Water clean hydrocarbons, non-corrosive Packed Box chemicals at moderate pressures

Not Applicable

Pumps taking suction from pumps where Packed Box leakage can be redirected to the sumps

Not Applicable

Typical mechanical seal arrangements for centrifugal pumps are shown in Figure 1.9. Where external seal flushing is required, the process engineer should make suitable provision to supply the flush liquid. API-610 provides recommendations on the seal flushing plan for centrifugal pumps for different services (refer Figures 1.10 and 1.11)

The bubble temperature of the external flush fluid should be about 10°C higher than the maximum operating temperature at operating pressure to avoid vapourisation of the fluid and consequent vapour locking.


Material of Construction In the petroleum and petrochemical industries, the selection of material of construction of a pump is usually dictated by considerations of corrosion, erosion, personal safety and liquid contamination. Tables 1.2 and 1.3 based on the recommendations of API-610 can serve as a useful guide to the process engineer for selection of material of construction of pumps. Obtain the recommendations of Specialist/ Mechanical group to verify these materials of construction and specify these recommendations in the process data sheets.

Table 1.2: Material Class and Material Class Abbreviation Table 1.3 : Material Recommendations for Different Services Service Fresh water, condensate, cooling-tower water Boiling water and process water Boiler feed water - Axially split - Double casing (barrel) Boiler circulator Foul water, reflux drum water, water draw and hydrocarbons containing these waters, including reflux streams Propane, butane, liquefied petroleum gas and ammonia (NH3) Diesel oil; gasoline; naphtha; kerosene; gas oils; light, medium, and heavy lube oils; fuel oil; residuum; crude oil; asphalt; synthetic crude bottoms Noncorrosive hydrocarbons, e.g. catalytic reformate, isomaxate, desulfurized oils Xylene, toluene, acetone, benzene, furfural, MEK, cumene Sodium carbonate, doctor solution Caustic (sodium hydroxide), concentration of ≤ 20% Seawater MEA, DEA, TEA – stock solutions DEA, TEA – lean solutions MEA – lean solution (CO2 only) MEA – lean solution (CO2 and H2S) MEA, DEA, TEA – rich solutions Sulfuric acid concentration 85% 85% - 15% 15% - 1% 1% Hydrofluoric acid concentration of >96% Notes : 1.

Temperature Range (°F) 200 >200 >200 350
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