Heat and Mass Balance Heat and mass balance is a document produced by process design engineers while designing a process plant. Sometimes heat and mass balance is not a separate document but appears alongside the Process Flow Diagram (PFD). A heat and mass balance sheet represents every process stream on the corresponding PFD in terms of the process conditions. Normally a heat and mass balance sheet reports following data for a process p rocess stream. 1. 2. 3. 4. 5. 6. 7. 8.
Normal operating temperature and pressure. Normal volumetric or mass flow rate. If multiple phases are involved, flow rate for each phase should be reported. Density at normal operating temperature and pressure conditions. If the stream has multiple phases, density for every phase should be reported along with the overall density. Viscosity for each phase in the stream should be separately reported. If gases are present, vapor fraction should be reported. Specific heat ratio Cp/Cv and compressibility factor should be reported for gaseous phase. Molecular weight for each should be reported separately. separately. Enthalpy flow for each stream is also reported sometimes in KJ/hr. KJ/hr.
Heat and mass balance calculations for a process are performed by applying the mass balance equation and the energy balance equation to each equipment. This provides the solver with a set of equations. Above mentioned properties of each stream are the unknown variables. This system has a unique solution when number of unknown variables are equal to number of equations. Therefore some variables are fixed to solve the system. If inlet streams are fully known and defined then the system is solved to know the outlet streams. If the required properties of outlet streams are fixed, then system can be solved to know what should be the inlet to get the required outlet streams.
Process Flow Diagram (PFD) Process Flow Diagram (PFD) is a drawing which essentially captures the process flow for a processing plant. PFD is used to capture the main process equipments, main process stream, process/design conditions in these equipments and the basic process control scheme in a single drawing. Entire process of a plant can be described using a few interconnected PFDs. A PFD should normally contain the following information about the plant process. 1. 2.
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Main process equipment with reference tag numbers, name. Process operating and design conditions are also usually provided. Main process streams are normally provided with reference stream numbers. It should be noted that streams are different than lines and stream numbers are not related to line numbers in any way. way. The streams that normally do not have any flow are indicated with an abbreviation NNF (Normally No Flow). Basic process data for each stream is sometimes given in the PFD against each stream number. This includes data such as operating temperature, pressure, flow rate, compositions etc. for each process stream. Sometimes, this process data is represented for each stream number, in a separate drawing known as heat and mass balance. Design conditions for a stream are not normally indicated in a PFD. Important isolation valves are also indicated in the PFD. Not all manual valves appear in the P&ID, only a few which can improve the understanding of a process from the PFD. Some valves are indicated as normally closed or locked closed depending on requirement. Automatic valves - motor operated valves / emergency shutdown shutdown valves / control valves appear on the PFD without the associated tag numbers. The purpose is better description of process. Associated control elements are also represented very briefly on the PFD. Notes are added wherever required to improve the understanding of the p rocess from PFD. Legend is a list of symbols used on the PFD with brief explanation. This ‘legend’ can appear on each sheet of PFDs or can appear on a single sheet with other sheets referring
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to a ‘Legend Sheet’. Interconnections from one PFD sheet to another are used for process streams and instrument control signals to maintain continuity betwee n different drawings.
Some items which appear on the P&ID but may not appear on the PFD are – safety valves, detailed instruments, lines, fittings, drains vents and tag numbers for all of them. A variation of the process flow diagram is a utility flow diagram (UFD) which captures the essence of utilities required for the process such as, steam, nitrogen, water etc.
Piping and Instrumentation Diagram – P&ID Piping and Instrumentation Diagram (P&ID) is a drawing elaborating the details of piping and instrumentation of a processing plant, developed at the design stage. P&ID is later used for assistance for construction of the corresponding plant and for operating that plant. P&IDs of a plant are developed by process design engineers and are followed by instrumentation and piping engineers. A P&ID is normally developed from a Process Flow Diagram (PFD) which captures the basic process flow, flow, at the design de sign stage of a pl ant A P&ID should provide following data to piping and instrument engineers, to construction teams and to the operators: 1.
Equipment – tanks, vessels, heat exchangers, pumps, compressors, columns etc. have to be indicated with type, reference tag numbers, basic design data, spares etc. 2. Lines – reference tag numbers, piping material class, line size, fluid service, insulation type and thickness etc. Sometimes process data such as line operating pressure, temperature and flow rate is also represented on the P&ID lines. 3. Some other piping requirements – such as slope, special insulation such as heat tracing, minimum / maximum piping distance requirements along with their values are also shown on P&IDs. 4. Manually operated piping valves – valve type (ball valve, gate valve, check valve etc.), valve size, Locked closed/open, sealed closed/open, normally closed/open etc. 5. Piping fittings – Flanges, reducers/expanders, spectacle blinds, spacers, strainers etc. along with their size wherever necessary. necessary. 6. Drains and Vents – are usually indicated using typical symbols along with their size and type (single valve, double valve etc.). 7. Automated valves – Shutdown valves (SDV), control valves, blowdown valves (BDV) are indicated with size if it is known. Also fail position (fail open/fail close/fail in position) is indicated for each of these valves. Actuator connection and type is indicated. Reference instrument tag numbers are attached to every automatic valves. 8. Safety Valves – Pressure relief valve (PRV) or Temperature relief valve (TRV) are indicated with their instrument tag numbers, setpoints, types are indicated by different symbols. 9. Instruments – Gauges, transmitters, local indicators, DCS indicators, interlocks and other functions have to be shown in detail on the P &ID. Interconnection between these elements has to be indicated by different types of instrument signals (hardwired signal, soft signal, pneumatic or hydraulic signal etc.). The location of the instrument elements (field mounted or DCS) is indicated by difference between symbols. 10. Notes – are written wherever required to improve clarity for anyone referring to the P&ID. Sometime ‘Hold’ is used to indicate uncertainty about relevant data. 11. Interconnections (OPC) – are shown between lines (piping OPC) and instrument signals (Instrument OPC) present on two different P&ID sheets. Sometime these interconnectors are also assigned with a unique tag number. For easy identification of the connections between two P&IDs. A connector present on two different drawing connection a line or a signal carries the same tag number. number. Because of the numerous details involved in P&IDs for each equipment, usually only one main equipment is shown on one P&ID sheet with related instruments and piping
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to a ‘Legend Sheet’. Interconnections from one PFD sheet to another are used for process streams and instrument control signals to maintain continuity betwee n different drawings.
Some items which appear on the P&ID but may not appear on the PFD are – safety valves, detailed instruments, lines, fittings, drains vents and tag numbers for all of them. A variation of the process flow diagram is a utility flow diagram (UFD) which captures the essence of utilities required for the process such as, steam, nitrogen, water etc.
Piping and Instrumentation Diagram – P&ID Piping and Instrumentation Diagram (P&ID) is a drawing elaborating the details of piping and instrumentation of a processing plant, developed at the design stage. P&ID is later used for assistance for construction of the corresponding plant and for operating that plant. P&IDs of a plant are developed by process design engineers and are followed by instrumentation and piping engineers. A P&ID is normally developed from a Process Flow Diagram (PFD) which captures the basic process flow, flow, at the design de sign stage of a pl ant A P&ID should provide following data to piping and instrument engineers, to construction teams and to the operators: 1.
Equipment – tanks, vessels, heat exchangers, pumps, compressors, columns etc. have to be indicated with type, reference tag numbers, basic design data, spares etc. 2. Lines – reference tag numbers, piping material class, line size, fluid service, insulation type and thickness etc. Sometimes process data such as line operating pressure, temperature and flow rate is also represented on the P&ID lines. 3. Some other piping requirements – such as slope, special insulation such as heat tracing, minimum / maximum piping distance requirements along with their values are also shown on P&IDs. 4. Manually operated piping valves – valve type (ball valve, gate valve, check valve etc.), valve size, Locked closed/open, sealed closed/open, normally closed/open etc. 5. Piping fittings – Flanges, reducers/expanders, spectacle blinds, spacers, strainers etc. along with their size wherever necessary. necessary. 6. Drains and Vents – are usually indicated using typical symbols along with their size and type (single valve, double valve etc.). 7. Automated valves – Shutdown valves (SDV), control valves, blowdown valves (BDV) are indicated with size if it is known. Also fail position (fail open/fail close/fail in position) is indicated for each of these valves. Actuator connection and type is indicated. Reference instrument tag numbers are attached to every automatic valves. 8. Safety Valves – Pressure relief valve (PRV) or Temperature relief valve (TRV) are indicated with their instrument tag numbers, setpoints, types are indicated by different symbols. 9. Instruments – Gauges, transmitters, local indicators, DCS indicators, interlocks and other functions have to be shown in detail on the P &ID. Interconnection between these elements has to be indicated by different types of instrument signals (hardwired signal, soft signal, pneumatic or hydraulic signal etc.). The location of the instrument elements (field mounted or DCS) is indicated by difference between symbols. 10. Notes – are written wherever required to improve clarity for anyone referring to the P&ID. Sometime ‘Hold’ is used to indicate uncertainty about relevant data. 11. Interconnections (OPC) – are shown between lines (piping OPC) and instrument signals (Instrument OPC) present on two different P&ID sheets. Sometime these interconnectors are also assigned with a unique tag number. For easy identification of the connections between two P&IDs. A connector present on two different drawing connection a line or a signal carries the same tag number. number. Because of the numerous details involved in P&IDs for each equipment, usually only one main equipment is shown on one P&ID sheet with related instruments and piping
Material Selection Diagram (MSD) What the Material Selection Diagram (MSD) show? A typical Material Selection Diagram (MSD) normally indicates following items: 1. 2.
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Important equipment in a facility such as pumps, compressor, heater, piping, specific valves, etc. Specify material selected for each of the following equipment and piping itmes Columns : shell, internals, tray, lining Heat exchanger: shell, channel, tubes, tube sheet, lining Air Fan Cooler: headers, tubes, fins Tanks: shell, roof, bottom, internals Pipeline Valve Furnaces: coils (convection, radiant, steam), refractory Pumps: casing, impeller impel ler,, pump material group Following material/fabrication requirements are also normally indicated on a Material Selection Diagram (MSD) Corrosion allowance PWHT or Stress Relieving Wet sour service requirements Hardness limitation Specific impact test requirements (i.e. MDMT, MDMT, etc.) Following optional information can also be indicated on a Material Sele ction Diagram (MSD) Process data: design/operating Corrosion control and monitoring information Corrosion Monitoring Probes/Methods Probes/Methods – location & type Chemical Injection – location & type Sampling points Cathodic protection – location & type Materials Balances percentage of severe sev ere corrosive components (e.g. H2, S, H2S, CO2, HF, HF, chloride, etc.) Partial pressure of Severe Corrosive Components (e.g. H2, H2S, NH3, HCl, etc.) Detail information for spec break in piping (i.e. at valves, tee, cross, dead leg, etc.) Specific Notes (e.g. upset condition, short notes for corrosion control, etc.) References
Typical Instrument Datasheets Typical Control Valve Datasheet for Pneumatically Actuated Valves – Control valves are typically operated with instrument air and are therefore characterised as pneumatically actuated valves. In order to be able to order the best control valve suited for the application, the user has to provide the valve manufacturer with all the necessary information to select and design a suitable control valve. Most important information to be given is type of the valve, range of fluid flow rates, corresponding range of pressure and temperature at the inlet and outlet of valve etc. Typically normal/minimum/maximum temperature, flow and pressure drop values are given for the vendor to correctly size the control valve. Typical Motor Operated Valve Datasheet – In order to procure the best MOV suited for the application, the user has to provide the valve manufacturer with all the necessary information to select and design a suitable MOV. Information such as – process conditions, line size, valve body type, information for the motor, opening and closing time requirements for the valve etc. – has to be clearly specified in the datasheet for MOV. MOV. Typical Safety Relief Valve Datasheet – When ordering a safety relief valve, valv e, the user has to provide
the Manufacturer with a specification sheet (datasheet) that specifies all necessary information for that relief valve. The datasheet of a safety relief valve should include the following items – General information, information of protected equipment, applicable standards, process conditions (pressure, temperature, relieving rate etc.), type, material and tentative size for the relief valve.
Typical P&ID arrangement for 3 phase separator vessels
3 phase separators are commonly used in upstream oil and gas industry to separate oil, gas and water stream coming from the oil wells. This typical P&ID arrangement can be modified and used for other separator vessels as well.
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Proper vessel symbol should be selected first of all, as shown in the presented drawing. This should be selected from the list of equipment symbols on the legend sheets of a particular project. Separator vessel internals should then be indicated as per proper symbols on the legend sheets. These internals can be inlet vane, vortex breaker on the outlet lines, demister pads on gas outlets, weir plate separating the oil and water compartments etc. All the nozzles on the separator vessel should then be correctly represented with size and flanges. This includes inlet and outlet nozzles, drains, vents, PSV connection and instrument nozzles, as shown in the sample drawing presented here. Typical instrumentation on the vessel would be level gauges and transmitters on oil and water compartments of the vessel plus pressure gauge and transmitters linked to p ressure control or alarms as applicable. Inlet and outlet lines are the next to be drawn up. Line number, material class, size etc. is to be correctly assigned to each of the lines. Isolation valves, spectacle blinds, spacers etc. to be used for maintenance should be drawn up next on the inlet / outlet lines. The spectacle blinds, spacers etc. are usually connected right next to the isolation valves and equipment nozzles, as indicated in the sample drawing presented here. Instrumentation on the vessel should be drawn up next. Typically this would include level gauges, level transmitters, pressure gauges, pressure transmitters as per requirement for control, alarm and trip if applicable. The sample drawing presented here only indicates transmitters, but generally they are accompanied by gauges for local indication and also transmitters for alarms and trips. Various control valves should be drawn up next wherever applicable. Sample drawing indicates level control on oil and water outlet lines. Plus pressure control is indicated on the vapor
outlet to flare. These control valves should be equipped with either a bypass or handwheel as per project standards, to continue vessel ope ration in case of control valve maintenance. 8. Drains should be provided either on the vessel or on the bottom outlet lines for complete draining of the vessel and associated piping for maintenance purpose. Sample drawing has indicated drains on the outlet lines through which the vessel and piping can be completely drained. Usually the vessel also has nozzles connecting it directly to the draining system. 9. Vents can be present either on the vessel itself or on the vapor outlet line, so that the vessel and associated piping can be completely vented for maintenance. Vent connected directly to vessel is indicated in the sample drawing. 10. In most cases the vessel is provided with a blanketing gas connection. This blanketing connection can be with or without pressure control. Although not indicated in the sample drawing, it is important to consider the blanketing gas connection to the vessel. 11. For purging the vessel with nitrogen, a connection can be provided directly on the vessel. In some cases purging can be done with steam. 12. All the guidelines given here are very general and may be modified as per specific requirements of any particular project.
Typical P&ID arrangement for pumps
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Proper pump symbol should be selected first of all, as shown in the presented drawing. This should be selected from the list of equipment symbols on the legend sheets of a particular project. All the nozzles on the pump should then be correctly represented with size and flanges. This includes inlet and outlet nozzles and casing drains and vents as shown in the sample drawing presented here. Generally, the suction and discharge nozzles on the pump are smaller than suction and discharge line sizes. Appropriate reducer / expander to be cle arly indicated in such cases. Inlet and outlet lines are the next to be drawn up. Line number, material class, size etc. is to be correctly assigned to each of the lines. Isolation valves, spectacle blinds, spacers etc. to be used for maintenance should be drawn up next on the inlet / outlet lines. The isolation valves on suction and discharge lines should be
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‘Locked Open’ in case of automatic pump start-up. Inlet line to the pump is to be fitted with a strainer for pump protection. This strainer can be equipped with a pressure differential gauge to monitor blockage in the strainer. Pressure gauges are normally to be p rovided on suction and discharge of the pump. In addition, pressure transmitters connected to Emergency Shutdown (ESD) system can also be provided as per requirements. A check valve should be normally provided on the pump discharge to avoid reverse flow when the pump is not in operation. Downstream to the check valve on the pump discharge, minimum flow recirculation line for the pump needs to be provided. A flowmeter should be provided before the minimum flow line, as shown on the presented sample drawing. A flow control valve with or without bypass is then to be provided on the minimum flow recirculation line. The isolation valves for this control valve need to be locked open or sealed open and the FCV should be of ‘Fail Open’ type. The minimum recirculation line is normally routed back to the suction vessel of the pump. Drains and vents to be provided on the suction / discharge lines, minimum flow line and on pump casing, so that the pump and associated piping can be completely drained for maintenance. For purging the pump with nitrogen, a connection should be provided right after isolation valve on the suction line. This connection can also be used as a drain. Temperature gauges and transmitters to be provided as per requirements for operating and controlling the equipment. All the guidelines given here are very general and may be modified as per specific requirements of any particular project.
Typical P&ID arrangement for Heat Exchangers
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Proper equipment symbol should be selected first of all, as shown in the presented drawing. This should be selected from the list of equipment symbols on the legend sheets of a particular project. All the nozzles on the exchanger should then be correctly represented with size and flanges. This includes inlet and outlet nozzles, drains, vents, utility connections etc.
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Inlet and outlet lines are the next to be drawn up. Line number, material class, size etc. is to be correctly assigned to each of the lines. If the unit is envisaged to be in operation while the exchanger is under maintenance, then bypass lines should be drawn up on shellside, tubeside or on both sides as shown in the drawing presented here. Isolation valves, spectacle blinds, spacers etc. to be used for maintenance should be drawn up next on the inlet / outlet lines. Bypass lines to be fitted with normally closed isolation valves. Thermal relief valve should be provided where required. Generally thermal relief valves are required on the cold liquid streams, when there is a possibility of blockage in the heating medium on the other side of exchanger. In case of such blockage, there is possibility of overheating the cold stream and hence requirement for thermal relief valve. Discharge of a relief valve to be routed to an appropriate, safe location. Drains and vents to be provided on both sides of the exchanger (hot and cold sides), either on the exchanger itself or inlet / outlet piping, so that the equipment can be completely drained for maintenance. For fouling service on the tubeside, utility connections should be provided as indicated in the presented drawing, for cleaning purpose. Temperature and pressure gauges and transmitters to be provided as per requirements for operating and controlling the equipment. Normally temperature monitoring is required for the process side of the heat exchanger. Also generally temperature control is implemented on the process side of the exchanger. All the guidelines given here are very general and may be modified as per specific requirements of any particular project.
Typical P&ID arrangement for Centrifugal Compressor Systems
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Proper centrifugal compressor symbol should be selected first, as shown in figure-1. Normally, a centrifugal compressor is accompanied by a Knock Out Drum (KOD) at the compressor suction and an after-cooler at the compressor discharge, as per a typical compressor PFD. Symbols for these equipment should also be placed on the P&ID before proceeding ahead. All the equipment symbols should be selected from the legend sheets of a particular project. All the nozzles on the compressor, suction drums and after-cooler should then be correctly represented with size and flanges. This includes inlet and outlet nozzles and equipment drains / vents as shown in the typical P&ID in figure-1.
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Centrifugal compressor suction KOD is intended for removing the entrained liquids before sending gas to the compressor. Demister, mesh pad etc. are used in the knock out drum to efficiently remove the liquid droplets. Compressor after-coolers are generally air coolers and the related fan, motor etc. should be clearly indicated on the P&ID. If cooling water is used, proper symbol for a heat exchanger should be used. Inlet, outlet lines for each equipment, anti-surge line, drain/vent lines, line to the relief valve etc. are the next to be drawn up. Line number, material class, size etc. is to be correctly assigned to each of the lines. Isolation valves, spectacle blinds, spacers etc. to be used for maintenance should be drawn up next on various lines between the equipment. Requirement for isolation valves, spectacle blind, spaces etc. depend on the project standards, which should be followed while indicating these on the P&ID. Sometimes, to minimize the number of isolation valves between the equipment, they can be placed only at the suction KOD inlet which is inlet of the centrifugal compressor system and discharge of the after-cooler which turns out to be the outlet of the centrifugal compressor system. Spectacle blinds or spacers can be used for isolation between individual equipment for quick maintenance. This is simply a guideline and project standards need to be followed when indicating the isolation requirements. 7.A check valve should be normally provided on the compressor discharge to avoid reverse flow when the pump is not in operation. Pressure relief valves can be provided on the compressor discharge line, downstream to the check valve, to protect the equipment downstream of compressor. Pressure gauges should be provided on suction and discharge of the compressor. Level gauges need to be located on the compressor suction knock out drum and temperature gauges on inlet, outlet lines for the after-cooler. Pressure transmitters should be provided on compressor suction and discharge line. A flow transmitter should be provided on compressor suction line. Signals from these transmitters are sent to an ‘Anti-Surge Controller’. Based on the gas flow and differential pressure head developed by the compressor, the anti-surge controller operates the anti-surge valves to prevent compressor surge condition. An anti-surge line from the after-cooler discharge to the suction KOD inlet should be provided for anti-surge control. When the compressor approaches surge condition (low flow, high differential head), the anti-surge valves open up to lower the pressure differential and circulate higher gas flow. Sometimes, a performance controller can be included in the centrifugal compressor system to control the rotating speed (RPM) of the compressor based on inlet pressure, flow etc. in order to achieve optimum performance. Performance controller will typically adjust the motor/turbine speed. Level transmitters provided on the suction knock out drum are responsible for liquid level control in the drum. Alarms are usually provided for high and high high liquid level conditions. Temperature transmitter can be provided on after-cooler for temperature control by sending a signal to adjust the fan speed of the air-cooler. Emergency Shutdown (ESD) valves can be provided on inlet / outlet lines of the compressors system to isolate whole system in case of a shutdown. The inlet line of the suction KOD corresponds to inlet of the compressor system. After-cooler discharge and liquid outlet of suction knock out drum correspond to the outlet lines of the compressor system. Shutdown valves can be located on these lines as shown in figure-1. Drains and vents to be provided on the suction / discharge lines, compressor casing, suction Knock Out Drum, air cooler body etc. for completely draining/venting compressor and associated piping, for maintenance. For purging the compressor system, a nitrogen connection can be provided right after the first isolation valve on the suction KOD inlet l ine.
Typical P&ID arrangement for Pig Launchers / Pig Receivers
(*) Refer to EnggCyclopedia’s Typical P&ID arrangement for PSVs Pig launchers and receivers are commonly used in upstream oil and gas industry for periodic cleaning of pipelines carrying crude oil, natural gas and water from oil wells. A pig is a bullet shaped object which fits the pipeline from inside. The pig launcher launches the pig into pipeline and the upstream pressure pushes the pig to other end of the pipeline where it is received by the pig launcher. Hence generally arrangement for pig launchers and receivers are essentially the same, except for the difference between ‘Kicker line’ position for launchers and receivers. The sample drawing presents this general arrangement common to pig launchers and receivers.
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Proper equipment symbol for pig launcher (vertical or horizontal) should be selected first of all, as shown in the presented drawing. This should be selected from the list of equipment symbols on the legend sheets of a particular project. The major and minor barrels of the pig trap should be indicated as shown in the sample drawing. Minor barrel size is equal to pipeline size and the major barrel size is slightly larger. All the nozzles on the pig launcher should then be correctly represented with size and flanges. This includes door on the launcher, pig outlet to pipeline, kicker line, balancing line, PSV connection, purge, vent, drain and instrument nozzles, as shown in the sample drawing presented here. Typical instrumentation on the pig launcher would be pressure gauges and transmitters and pig indicators to know if the pig has been launched (or arrived in the case of pig receivers). Different lines connected to the pig launcher are the next to be drawn up. Line number, material class, size etc. is to be correctly assigned to each of the lines. Kicker line is used to pressurize the upstream side of pig so it can be launched. In case of receiver, kicker line provides an outlet for fluids arriving in the pig trap. Normally when pigging is not being performed, kicker line is closed using normally closed valve. Balancing line connecting the kicker line to minor barrel of the pig launcher, helps lower the pressure differential so that sudden shooting of the pig will not damage downstream automatic valves. 7.A bypass line of the pig launcher is the normal route for the fluids when pigging is not taking place. This section upstream to the shutdown valve at beginning of pipeline can be protected against overpressure as indicated in the sample drawing.
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The hand operated valve (HV) on the bypass line is used to create a pressure differential for launching the pig (also for receiving the pig). A pressure differential indicator (PDI) has to be available to the HV operator to monitor the pressure differential. On the outlet of the pig launcher, another hand operated automatic valve is provided to open up the launcher upon pressurization. The pig launcher(and receiver) are also protected against overpressure with a PSV which discharges to flare. Typical representation of PSVs can be referred to in another article. Isolation valves, spectacle blinds, spacers etc. to be used for maintenance should be drawn up next, on various lines to and from the pig trap. The spectacle blinds, spacers etc. are usually connected right next to the isolation valves and equipment nozzles, as indicated in the sample drawing presented here. Drains should be provided either on major or minor barrel or on both for complete draining of the pig trap after the pig is launched or received. Sample drawing has indicated drains on both the barrels. These drains are connected to the closed drain system. Vents to flare and to atmosphere are required on pig launchers. Venting to flare for depressurization of the pig launcher can be achieved using bypass on the relief valve. For maintenance, when pig is not in operation it can b e vented to atmosphere. 14.A utility connection is required to purge the pig launcher / receiver after the pigging is done and the pig trap is depressurized and drained. A nitrogen connection should normally be provided as indicated in the sample drawing. Most of the guidelines mentioned for pig launchers also hold good for pig receivers.
Pressure Safety Valves – Typical P&ID arrangement
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The sample drawing presented here represents a typical arrangement generally used to represent safety valves or relief valves on P&ID. First of all a proper safety valve symbol should be selected to represent the control valve as per the project standards. For protecting equipment that are not spared and equipment that cannot be isolated without disrupting the plant / unit a spare safety valve is recommended to be provided as shown in the sample drawing.
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Generally, the safety valve inlet / outlet nozzles are smaller than the corresponding line sizes. This change in diameter should be clearly indicated in the P&ID with reducer and expander. Block valves should be provided upstream and downstream of the safety valves in case of shutdown and maintenance. Normally provision is made to keep these valves locked or sealed open. The spare safety valve is kept locked or sealed closed, as indicated in the sample drawing. 5.A vent valve is normally provided between the safety valve and upstream block valve. Normally, bypass should be provided for safety valves for process or start-up requirements. Type, number and size of bypass valves will depend on the project standards. Depending on the service handled, the discharge from PSV can be either routed to flare system for hydrocarbon service, for closed/open drain systems or to atmosphere at a safe location for non-hazardous service. The inlet lines to the safety valves are always sloped toward to protected equipment and the outlet lines from the safety valves are always sloped towards the flare header / the knock out drum or the safe location. When a PSV is connected to the flare system, the inlet line piping should be equipped with a spool piece to facilitate dismantling, as indicated in the sample drawing. For PSVs discharging to atmosphere, this is not required.
Control Valves – Typical P&ID arrangement
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The sample drawing presented here represents a typical arrangement generally used to represent control valves on P&ID. Depending on the projects legend sheets, control valves may be represented by globe or gate valves. Here a globe valve symbol is used. First of all a proper valve symbol should be selected to represent the control valve as per the project standards. Generally, the control valve size is smaller than the corresponding line size. This change in diameter should be clearly indicated in the P&ID with reducer and expander. Block valves should be provided upstream and downstream of the control valves in case of shutdown and maintenance. 4.A drain valve is normally provided between the control valve and upstream block valve. If the control valve is of ‘Fail Open’ type, this drain valve is sufficient to drain the piping segment. If the control valve is of ‘Fail Close’ or ‘Fail in Position’ type, then additional drain valve is required between the control valve and downstream block valve as shown in the sample drawing. Normally, either a bypass or a hand wheel is provided for control valves which are under continuous service. If two or more control valves are installed in parallel, b ypass or hand wheel is not required. The choice between providing either a bypass or a hand wheel for the control valve is made based on the size of the control valve. For control valves bigger than a certain size, provision of hand wheel is preferred. For control valves smaller than certain size, provision of bypass with block valves is preferred. For control valves on certain critical services, a spare control valve may be installed on the bypass of main control valve. This limiting control valve size between hand wheel and bypass is specific for a project and may vary from one project to another. If the control valve is equipped with a hand wheel, then only the drain between control valve and upstream block valve is sufficient for draining by opening the control valve using hand
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wheel. Normally globe valve is selected as the bypass valve on the control valve as it allows better control with opening. Additional details such as failure position, tightness class, # rating etc. are also indicated on the P&ID for control valves, as per the project standards.
Typical P&ID arrangement for Storage Tanks
Storage tanks of various kinds are used to store process fluids of various types, under different process conditions. But the basic arrangement remains roughly the same for different types of storage tanks.
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Proper tank symbol should be selected first of all, as shown in the presented drawing. This should be selected from the list of equipment symbols on the legend sheets of a particular project. Tank internals should then be indicated as per proper symbols on the legend sheets. These internals can be inlet pipe, vortex breaker on the outlet lines etc. All the nozzles on the storage tank should then be correctly represented with size and flanges. This includes inlet and outlet nozzles, overflow line, minimum recirculation line, blanketing gas line, drains, vents, PSV connection and instrument nozzles, as shown in the sample drawing presented here. Normally for large enough tanks a man-way has to be provided as indicated in the sample drawing for maintenance access. Inlet and outlet lines are the next to be drawn up. Line number, material class, size etc. is to be correctly assigned to each of the lines. Typical instrumentation on the tank would be level gauges and transmitters plus pressure gauge and transmitters. For tank under continuous operation a level control valve has to be provided as indicated in the sample drawing. For tank with blanketing gas a self regulating pressure
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valve has to be provided on the blanketing gas inlet line. Normally alarms / trips are provided for High High Pressure, High High Level, Low Low Pressure and Low Low Le vel. Isolation valves, spectacle blinds, spacers etc. to be used for maintenance should be drawn up next on the inlet / outlet lines. The spectacle blinds, spacers etc. can be connected right next to the isolation valves and equipment nozzles, as indicated in the sample drawing presented here. Drains should be provided on the tank bottom and on the bottom outlet lines for complete draining of the tank and associated piping for maintenance purpose. Vent has to be provided on top of the tank for complete venting of the tank for maintenance purpose. In some cases the tank may be open to atmosphere through vent during normal operation. In such cases a bird screen has to be provided on the vent line. For purging the tank with nitrogen or steam, a utility connection can be provided directly on the tank.
Typical Process Flow Diagram Amine Treating Unit
Usually crude oil extracted from geological sources is accompanied by hydrogen sulphide gas (H2S). This H2S is separated from rest of the oil at the atmospheric distillation unit along with lighter hydrocarbons and collectively termed as ‘sour gas’. H2S is separated from hydrocarbons at the amine treatment unit and H2S rich gas flow is sent to sulphur recovery unit (SRU) for extracting elemental sulphur from H2S gas. Amine treatment unit uses Methyl Di Ethanol Amine or MDEA to remove H2S and CO2 gases from other lighter hydrocarbon gases. An amine treatment unit involves two stages. First stage is an amine contactor where gases are bought in contact with amine and H2S and CO2 are absorbed in the liquid phase. Second stage is an amine regenerator where H2S and CO2 are stripped away from the liquid phase to regenerate the lean amine solution to be recirculated to the amine contactor column. Amine contactor is essentially an absorption column. The lean amine solution flows from top to the bottom of absorption column. The sour gas flows from bottom of the column to the top. H2S and CO2 are preferentially absorbed in the amine solution and sweet hydrocarbon gases are taken out from the column overhead. Amine solution rich in H2S and CO2 is taken out from the bottom of absorption column and taken to amine surge drum. The hydrocarbons condensed to liquid phase in the amine contactor flow along with the amine solution to amine surge drum which is a 3-phase separator and hydrocarbon condensate is separated from amine solution using a weir. Rich amine solution separated in the amine surge drum is then taken to the amine regenerator columns which is essentially a stripper column. The rich amine solution in introduced at the top of the column. This amine solution is taken out from the column bottom and fed to the amine reboiler which utilizes steam to boil off H2S and CO2 from the amine solution. These vapors are introduced at the column bottom they flow in contact with the rich amine solution to the top of the
regenerator column and are taken out from the column overhead. The vapors from column overhead are fed to a condenser to extract any entrained amine which is recycled to the column top. In this way, lean amine is regenerated at the bottom reboiler of the regenerating column and recycled to the amine contactor column. The acid gas (H2S and CO2) is removed from regenerator overhead and taken to the sulphur recovery unit (SRU).
Typical PFD for Centrifugal Compressor Systems The following figure-1 represents a typical process flow diagram (PFD) for a compressor system. Common equipment included in such systems are compressors, driver motors or turbines, suction knock out drums (KOD) to remove traces of liquid from the gas going into the compressor and aftercooler which help lower the temperature of the discharge gas from compressor. Often anti-surge controllers along with anti-surge valves are also part of this system to avoid operating the compressor at surge conditions.
Centrifugal compressors are typically driven by an electric motor or a steam turbine. The sample PFD in figure-1 indicates use of an electric motor. The driver motor or turbine is connected to the compressor by a shaft which can rotate at different speeds for which the motor or turbine is designed. Compressor manufacturer creates a ‘compressor map’ which is essentially a graph of compressor curves plotted at different rotational speed (RPM) values. For a given value of gas flow though the compressor, discharge pressure of can be controlled by controlling the rotational speed of the driver. Hence a pressure controller installed on the compressor discharge stream, sends a signal to the driver motor or turbine to control the rotational speed. Sometimes a compressor performance controller can be used which takes into account a lot of other parameters than just the discharge pressure, to effectively maintain the rotational speed. Presence of small liquid droplets in the gas compressor can be damaging to the compressor. Hence Knock Out Drums (KOD) at compressor suction are desirable to remove even small traces of liquid droplets from gas going to the compressor. These compressor suction drums may be equipped with demister pads and wire mesh to improve the efficiency of liquid droplet removal. When gas is compressed the gas temperature also rises along with its pressure, since there is not enough time to vent the heat to atmosphere. Often high temperatures of the compressed gas are not desirable hence air coolers can be installed at the compressor discharge to enable temperature control of the discharge gas. These are known as compressor after-coolers. Compressor surge is seen as a very dangerous and detrimental phenomenon for compressor systems,
because it causes the compressor to vibrate and damages the compressor parts. Compressor surge occurs due to high back pressure on the compressor discharge so that very small gas flow can be pushed through. This is indicated by a surge line on any compressor map. To avoid compressor surge the back pressure at compressor has to be lowered so that more gas flow can be circulated through the compressors. This can be accomplished by an anti-surge controller which opens the anti-surge valves so that excess pressure from the compressor discharge is vented to the compressor suction KOD. The anti-surge valves also enable more gas flow to be circulated through the system, avoiding prolonged compressor operation in the surge conditions.
Desalting of crude oil in refinery Purpose of crude oil desalting Crude oil introduced to refinery processing contains many undesirable impurities, such as sand, inorganic salts, drilling mud, polymer, corrosion byproduct, etc. The salt content in the crude oil varies depending on source of the crude oil. When a mixture from many crude oil sources is processed in refinery, the salt content can vary greatly. The purpose of desalting is to remove these undesirable impurities, especially salts and water, from the crude oil prior to distillation. The most concerns of the impurities in crude oil:
The Inorganic salts can be decomposed in the crude oil pre-heat exchangers and heaters. As a result, hydrogen chloride gas is formed which condenses to liquid hydrochloric acid at overhead system of distillation column, that may causes serious corrosion of equipment. To avoid corrosion due to salts in the crude oil, corrosion control can be used. But the byproduct from the corrosion control of oil field equipment consists of particulate iron sulfide and oxide. Precipitation of these materials can cause plugging of heat exchanger trains, tower trays, heater tubes, etc. In addition, these materials can cause corrosion to any surface they are precipitated on. The sand or silt can cause significant damage due to abrasion or erosion to pumps, pipelines, etc. The calcium naphthanate compound in the crude unit residue stream, if not removed can result in the production of lower grade coke and deactivation of catalyst of FCC unit
Benefits of Crude Oil Desalting
Increase crude throughput Less plugging, scaling, coking of heat exchanger and furnace tubes Less corrosion in exchanger, fractionators, pipelines, etc. Better corrosion control in CDU overhead Less erosion by solids in control valves, exchanger, furnace, pumps Saving of oil from slops from waste oil
Desalting process
The desalting process is completed in following steps:
Dillution water injection and dispersion Emusification of diluted water in oil Distribution of the emulsion in the electrostatic field Electrostatic coalescence Water droplet settling
Crude oil passes through the cold preheat train and is then pumped to the Desalters by crude charge pumps. The recycled water from the desalters is injected in the crude oil containing sediments and produced salty water. This fluid enters in the static mixer which is a crude/water disperser, maximizing the interfacial surface area for optimal contact between both liquids. The wash water shall be injected as near as possible emulsifying device to avoid a first separation with crude oil. Wash water can come from various sources including relatively high salt sea water, stripping water, etc. The static mixers are installed upstream the emulsifying devices to improve the contact between the salt in the crude oil and the wash water injected in the line. The oil/water mixture is homogenously emulsified in the emulsifying device. The emulsifying device (as a valve) is used to emulsify the dilution water injected upstream in the oil. The emulsification is important for contact between the salty production water contained in the oil and the wash water. Then the emulsion enters the Desalters where it separates into two phases by electrostatic coalescence. The electrostatic coalescence is induced by the polarization effect resulting from an external electric source. Polarization of water droplets pulls them out from oil-water emulsion phase. Salt
being dissolved in these water droplets, is also separated along the way. The produced water is discharged to the water treatment system (effluent water). It can also be used as wash water for mud washing process during operation. A desalting unit can be designed with single stage or two stages. In the refineries, the two stages desalting system is normally applied, that consists of 2 electrostatic Coalescers (Desalter).
Atmospheric Distillation Unit
Typical PFD for an Atmospheric Distillation Unit Crude oil is sent to the atmospheric distillation unit after desalting and heating. The purpose of atmospheric distillation is primary separation of various ‘cuts’ of hydrocarbons namely, fuel gases, LPG, naptha, kerosene, diesel and fuel oil. The heavy hydrocarbon residue left at the bottom of the atmospheric distillation column is sent to vacuum distillation column for further separation of hydrocarbons under reduced pressure. As the name suggests, the pressure profile in atmospheric distillation unit is close to the atmospheric pressure with highest pressure at the bottom stage which gradually drops down till the top stage of the column. The temperature is highest at the bottom of the column which is constantly fed with heat from bottoms reboiler. The reboiler vaporizes part of the bottom outlet from the column and this vapor is recycled back to the distillation column and travels to the top stage absorbing lighter
hydrocarbons from the counter current crude oil flow. The temperature at the top of the column is the lowest as the heat at this stage of the column is absorbed by a condenser which condenses a fraction of the vapors from column overhead. The condensed hydrocarbon liquid is recycled back to the column. This condensed liquid flows down through the series of column trays, flowing counter current to the hot vapors coming from bottom and condensing some of those vapors along the way. Thus a reboiler at the bottom and a condenser at the top along with a number of trays in between help to create temperature and pressure gradients along the stages of the column. The gradual variation of temperature and pressure from one stage to another and considerable residence time for vapors and liquid at a tray help to create near equilibrium conditions at each tray. So ideally we can have a number of different vapor-liquid equilibria at different stages of this column with varying temperature and pressure conditions. This means that the hydrocarbon composition also varies for different trays with the variation in temperature and pressure. The heaviest hydrocarbons are taken out as liquid flow from the partial reboiler at bottom and the lightest hydrocarbons are taken out from the partial condenser at the column overhead. For the in between trays or stages, the hydrocarbons become lighter as one moves up along the height of the column. Various other cuts of hydrocarbons are taken out as sidedraws from different stages of the column. Starting from LPG at the top stages, naptha, kerosene, diesel and gas oil cuts are taken out as we move down the stages of atmospheric column. The heaviest hydrocarbon residue taken out from partial reboiler is sent to the vacuum distillation column for further separation under reduced pressure. The different cuts of hydrocarbons taken out at this stage are the result of primary separation and undergo further processing before being transformed to end products.
Typical PFD Instrument Air Dryer and Filter System
Figure 1 - Typical PFD for air dryer and filter package
Instrument air is made available to the instrument air headers by compressing the atmospheric air. The compressed air being used for instruments is needed to be dry to a certain extent, whereas ambient air usually comes with moisture. When the moist air is compressed, some of the water content tends to condense under pressure and is removed using knock out drums at the discharge of instrument air compressors. The air coming out of knock out drums is still somewhat moist and further drying of this air is carried out by using ‘Instrument Air Dryer and Filter Systems’. Typically instrument air drying systems consist of two parallel vessels with instrument air drying beds. When moist air is passed through such a dryer, moisture from the air gets absorbed by this bed and dry, dehumidified air is passed through the outlet. The dried air is filtered to remove any particulate matter, possibly entrained from the dryer bed. When a dryer bed absorbs moisture from wet air, after some time it gets saturated and cannot absorb any more moisture. Hence it is needed to remove all the moisture content from this dryer bed, to regenerate it. This regeneration is carried out by passing hot air through the dyer, thus heating up the dryer bed to free the moisture. Due to high temperature of the regenerating air, it can accommodate higher moisture content. Hence the bed is dried by hot regeneration air and moisture is carried out to the atmosphere by this hot stream of humid air. To regenerate a dehumidifier bed, without interrupting the dryer operation, two dryer vessels are used in parallel as indicated in figure-1. While one ve ssel dehumidifies the wet air from compressor, the other dryer bed is regenerated by heating using hot air. Atmospheric air is used for dryer regeneration. A fan or blower is used to send atmospheric air to a heater which heats up the atmospheric air. The hot air is then passed through a dryer bed to remove moisture from the bed. Moist air from the dryer bed is released to atmosphere, using an on-off valve. When one dryer bed becomes saturated with moisture, on-off sequence valves are used to switch the drying operation is easily to the other bed which has been dried by hot air.
Typical PFD for Sour Water Stripper Column
Figure 1 – Typical PFD for a sour water stripper column
In upstream crude oil production and processing facilities, the produced water from oil wells is separated in the slug catcher. Generally this produced water contains salts, hydrogen sulphide, carbon dioxide etc. Salts are removed using a desalting unit. Due to presence of acidic gases present in the produced water, sometimes it is called as sour water. For removal of these gases such as H2S, CO2 etc, the sour water is sent to sour water stripper columns. Even in crude oil refining facilities, steam and water are often used in many units such as atmospheric distillation unit, naphtha hydrotreater unit, kerosene hydrotreater etc. These units produce sour water as a result of steam/ water coming in contact with sulphur products in the hydrocarbons. This sour water is also then sent to sour water stripper columns for H2S removal. The H2S removed is sent to sulphur recovery unit to produces liquid sulphur.
Typical process flow in a sour water stripping unit Typically a sour water flow in crude oil processing facility or in a refinery is not steady. Sour water is gathered from a number of different sources and treated in a single column. For upstream oil production and storage facilities, the produced water comes along with crude oil in a pipeline. During pigging of these pipelines vast quantities of sour water are produced in the slug catcher, which may far exceed the sour water stripper flow handling capacity. Hence a buffer vessel is generally provided upstream to the stripper column to accommodate extra sour water quantities in case of a peak e.g. pigging. Sour water from buffer vessel is sent to the sour water stripper column under level control. In case the flow to the column sees major fluctuations which may frequently disturb the column operation, flow control valve on the column inlet water line can be used with a cascading signal from buffer vessel level control. Gases flashed in the buffer vessel can be flared or sent to the sulphur recovery unit, if they are rich in H2S. The stripper column may use either steam or fuel gas to strip off the H2S dissolved in water. Water is introduced from top of the packing or trays section and steam/fuel gas flows upwards from the bottom of the trays/packing section as shown in the typical PFD in figure-1. Contact between water and vapor phase allows transfer of H2S from water to the gas phase (steam or fuel gas). Gases rich in H2S are removed from the top of the column and treated water is taken out from the bottom of the column, under level control for the liquid level of the bottom section of stripper column. If steam is used in the stripper column for removing H2S, then overhead condenser and reflux drum are required at the top outlet of the column as shown in typical PFD in figure-1. The vapor outlet line of the stripper column is also equipped with a pressure control valve to maintain the sour water stripper column overhead pressure. Steam used can be either taken directly from the utility steam and sent to column or the treated water from bottom of the column can be sent to a reboiler to produce steam which is circulated back to the column for H2S removal. If fuel gas is used instead of steam to remove H2S, reboilers, condensers, reflux drums etc. are not required. But the gases from column overhead outlet have a high hydrocarbon content. An analyzer is installed to detect the H2S content in the sour water stripper outlet. This analyzer generally transmits signal to the control room and steam/fuel gas flow can be adjusted from the control room in order keep the H2S content in treated water well below the allowable H2S content limit. Alternatively, a controller can be used to directly throttle the steam/fuel gas flow based on a setpoint of H2S content in the treated water.
Distillation Column
Distillation is a commonly known method for separation of two liquid components with different boiling points. The ease of separation through distillation usually depends on the difference between boiling points. For a significant difference between boiling points of two liquids, they can be separated by batch distillation where one liquid remains almost completely in liquid form at the boiling point of the other liquid. If the boiling points of two liquids to be separated are close to each other, the heavier liquid partially vaporizes at boiling point of the lighter liquid. Hence degree of separation is compromised in batch distillation. For such mixtures in vapor-liquid equilibrium conditions, both the phases – liquid and vapor – contain significant amounts of either component. But the compositions of both – liquid phase and vapor phase – depend on the temperature and pressure conditions. By manipulating the temperature and pressure conditions it is possible to achieve good degree of separation. Continuous distillation column uses variation of temperature and pressure conditions along the height of the column to get more volatile component at the top of the column and less volatile component at the bottom of the column. The mixture to be separated is introduced at somewhere along the height of a vertical column. If the mixture contains more of lighter component, then the inlet is closer to top of the column. Conversely if the mixture has more of the heavy component, then inlet is closer to bottom of distillation column.
The column is provided with heat by a reboiler which is continuously boiling the liquid from the bottom of the columns. And the vapors from the top of the column are continuously cooled and condensed by an overhead condenser provided at the top of the column. The heating and cooling actions of these heat exchangers are responsible for vapor liquid equilibrium conditions in the column. Also due the action of reboiler the bottom of a distillation column has highest temperature and pressure conditions. The condenser is responsible for lowest temperature and pressure conditions at the top of the column. A distillation column consists of a number of stages. Each of these stages is formed by a perforated tray. Liquid from the top condenser flows down from tray to tray to the column bottom. Vapors flow from bottom to top through the perforations in each of these trays. Thus trays provide the interface for vapor liquid contact and depending on the residence time on each tray the vapors and liquids tend to form vapor liquid equilibrium conditions. Hence each tray can be ideally thought of as vapor liquid equilibrium at different temperature and pressure conditions. The temperature and pressure decrease from tray to tray as we move from bottom to the top of the column, due to action of reboiler at bottom and condenser at top of column. The vapor-liquid contact at each tray enhances separation. Heavy component vapors get condensed when they are in contact with cold liquid from the top. Conversely lighter component gets vaporized and stripped away from the liquid phase. Hence high number of separation implies higher degree of separation. A very high number of trays are often required to separate very closely boiling liquids or to get very high purity which is required for pharmaceutical substances. All the above mentioned factors -reboiler, condenser, number of trays in a column – cause high concentrations of lighter component at top of the column and high concentration of heavy components at the bottom.
Centrifugal Compressor Surge Compressor Surge Centrifugal compressor surge is seen as a very dangerous and detrimental phenomenon in compressed air systems, dangerous because it causes the compressor to vibrate and detrimental because it causes damage to the compressor parts. Compressor surge only occurs in dynamic compressors (Axial and Centrifugal) due to their nature. To understand compressor surge, a solid understanding of how a compressor actually works is needed. A centrifugal compressor is a machine that imparts energy to the gas flowing through it. This e nergy is in the form of velocity and is imparted from compressor impeller to the gas. Kinetic energy of the gas is then converted to pressure head when gas is diffused, slowed down. Figure-1 indicates a schematic of a centrifugal compressor system which demonstrates this phenomenon. On the left is the suction side and the right is the discharge side. The centrifugal compressor is in the centre. Compressor draws in gas near the centre of the compressor impeller with a low energy and imparts kinetic energy as the gas gets hurled in radial direction by the rotating impeller. This kinetic energy is converted to pressure head near the impeller periphery when the gas slows it down in the diffuser and it is forced into the discharge line.
Figure 1: centrifugal compressor schematic To understand compressor surge phenomenon, imagine the following situation. A compressor is running at 80% of its maximum pressure output for 100% rpm producing 8 bar. Then the compressor starts to produce 100% of its possible pressure output at 10 bar. This now puts the operating point on the surge line as shown in the figure-2. As soon as the system pressure in the discharge line reaches 10 bar the compressor begins to surge.
Figure 2: Sample compressor map
Compressor surge can be understood by the help of schematic of a compressor impeller in figure-3. At point (1) on figure-3, suction end of a centrifugal compressor impeller, fluid has the lowest energy. As the gas moves to point (2) of figure-3, energy of the fl uid increases due to kinetic energy imparted by impeller. Energy reaches a maximum at point (3) on figure-3. When the compressor is imparting as much energy as it possibly can, i.e. 100% pressure at 100% rpm and backpressure at pump discharge is too high to be overcome, the fluid flow stalls near point (3). This means the pressure at point (3) increases because the kinetic energy changes to pressure as it slows to a stop. Thus the energy at point (3) is greater than at points (2) and (1) so the flow reverses and flows backward through the impeller.
Figure 3: Schematic of centrifugal compressor impeller When the flow reverses, energy and pressure at point (3) is relieved and drops down. Now the compressor can compress fluid, which it does and with the increase of pressure the backflow occurs again and this is the reason why compressor surge is a cyclic phenomenon. Compressor surge puts strain on many of the compressors parts such as the bearings, seals and the impeller itself and thus damage can occur if the compressor is left to surge. The vibration caused by the surging can severely damage the motor compressor coupling and also the baseplate. There are many methods of surge control in industry today and choosing the right one is difficult and very subjective, so choose wisely
Compressor Map Compressor maps are developed by the manufacturer of dynamic compressors. They are compressor equivalents of the pump performance curves. It is the performance chart of a specific compressor which manufacturer calculates and draws up for the unique design characteristics of that compressor. An example of an air compressor from a car turbocharger is shown in figure – 1.
Figure 1: Sample air compressor map A compressor map is two dimensional and has all the information an engineer needs for design purposes. In the sample compressor map represented in figure-1, the blue curved lines represent compressor curves for different impeller speed values with the uppermost line being the maximum speed that the compressor can reach. The skewed ellipses are the efficiency “islands” or the efficiency areas. The Y axis is the pressure ratio which is exp lained below and the X axis is the “air / gas flow before the turbo”. To read of a point from the compressor map is straight forward. For example the red circled point on the map, represents compressor output of 520 CFM (corrected air flow) at a pressure ratio of 2.1. At this point the compressor is spinning at 144000 rpm and has an efficiency of only 61% (indicated by the corresponding efficiency area).
The Y axis (Vertical Axis)
Y axis of a compressor map indicates pressure ratio. Pressure ratio is the ratio of the compressor discharge pressure to the compressor suction pressure. If the compressor suction pressure is known, pressure ratio can be decided to achieve required output. For example if the inlet pressure is 1bar (Atmospheric pressure) and it is required to boost the gas to a pressure of 2 bar, then the pressure ratio needs to be two. The same principal applies to industrial compressors except that they have higher pressure ratios, especially multi-stage compressors. The following is a formula of the calculation that has just been described: Outlet pressure = Inlet pressure × pressure ratio Thus if at sea level a certain compressor gives an outlet pressure of 2 bar and then you take the compressor to a much higher elevation the outlet pressure will be lower because the inlet pressure has dropped.
Efficiency Islands / Efficiency Areas
The “ellipses” can be used just like contours on geographical maps, except that here they show a range of efficiencies. Usually the efficiency islands converge to the centre of the compressor map as shown in figure-1, where the efficiency is at its maximum. This line where the efficiency islands on compressor maps converge is known as “Peak Efficiency Line”. Usually operating the compressor near “Peak Efficiency Line” is always the most de sirable as the most possible work output can be obtained using same or less work input.
Surge and Choke lines (Orange)
The orange line on the left hand side is the Surge line and the Orange line on the right hand side is the choke line. If the compressor operates on the left of the surge line, this can result in compressor surge. Compressor surge is a pulsating back flow of gas through the device. Compressor surge is a highly undesirable phenomenon as it can mechanically damage compressor parts and must be avoided. If the compressor operates on the right of the choke line then the compressor will experience choked flow. Choked flow is when the flow reaches the speed of sound and this is a problem because it limits the maximum flow rate through the compressor. Thus the choke line on a compressor map signifies its maximum flow rate limit . When designing a compressor system careful consideration needs to be taken to make sure that the designed operating point does not fall outside the surge and choke lines.
Max Flow and Max Pressure
The maximum flow that a compressor can handle is easily found on the sample compressors map, in figure-1. The point of maximum flow is the extreme right point on the map. The red circled point in figure-1 happens to be the point of maximum flow. If more flow needs to be pushed through then a different compressor is required. At the maximum flow point, compressor efficiency is at its lowest so it is highly desirable to use a different compressor. The maximum discharge pressure that a compressor can achieve is found using the uppermost point on the map. At this point the pressure ratio can be found and using the formula above the outlet pressure can be calculated. Compressor maps are very important in design of systems because they give you vital information on surge, choke and compressor speeds. They also let you know if your compressor is going to be efficient enough for your application.
Centrifugal Pump Start-up Procedure Centrifugal pumps: Centrifugal pumps convert energy of an electric motor or turbine into velocity or kinetic energy and then into pressure energy of the fluid being pumped. The energy changes occur around two main parts of the pump, impeller and volute or diffuser. Pump impeller is the rotating part that converts driver energy into the kinetic energy. The volute or diffuser is the stationary part that converts the kinetic energy into pressure energy. The pump driver can be either electric motor or a steam turbine depending upon application. These precautions must be followed before centrifugal pump start-up:
Do not operate the centrifugal pump below the minimum rated flows or with the suction or discharge valves closed. These conditions can quickly lead to centrifugal pump failure and physical injury. Always disconnect and lock out power to the driver before you perform any installation or maintenance tasks. Centrifugal pump start-up in reverse rotation can result in the contact of metal parts, heat generation, and breach of containment. Flush and clean the system thoroughly to remove dirt or debris in the pipe system in order to prevent failure at initial pump start-up. Bring variable-speed drivers (if installed) to the rated speed as quickly as possible. Generally if the temperatures of the pumped fluid will exceed 200°F (93°C), then warm up the pump prior to pump start-up. Circulate a small amount of fluid through the pump until the casing temperature is within 100°F (38°C) of the fluid temperature prior to pump start-up to avoid thermal shock to the liner and impeller and prevent damage of mechanical seal.
General centrifugal pump start up procedure:
Before pump start-up you must pe rform these tasks:1. Open the suction valve. 2. Open any recirculation or cooling lines. 3. Fully close or partially open the discharge valve, depending on system conditions. 4. Start the driver. 5. Slowly open the discharge valve until the pump reaches the desired flow. 6. Check the pressure gauge to ensure that the pump quickly reaches the correct discharge pressure. 7. If the pump fail to reach the correct pressure, perform these steps: A. Stop the driver. B. Prime the pump again. C. Restart the driver. 8. Monitor the pump while it is operating. A. Check the pump for bearing temperature, vibration, and noise. B. If the pumps exceed normal levels, then shut down the pump immediately and correct the problem. 9. Repeat steps 7 and 6 until the pump runs properly.
