The FCC wet gas compressor’smajor function is reactor pressurecontrol. The machine must com-

press gas from the main column over-head receiver to gas plant operatingpressure while maintaining stable regen-erator-reactor differential pressure (Fig-ure 1). Typically, reactor-regeneratordifferential pressure must be controlledwithin a relatively narrow +2.0psi to–2.0psi (+0.14 to –0.14 bar) range to per-mit stable catalyst circulation. The wetgas compressor and its control systemplay a vital role in maintaining steadyreactor operating pressure. To be sure,optimum FCC operation requires bal-ancing regenerator and reactor pressuresto wet gas and air blower constraints.Nonetheless, reactor pressure is pre-sumed constant throughout this articleto simplify discussions.

Reactor operating pressure is regu-lated by the main column overheadreceiver pressure and system pressuredrop from the reactor to the overheadreceiver. The wet gas machine needs tohave sufficient capacity to compressreceiver wet gas to the gas plant operat-ing pressure. Reactor effluent composi-tion, overhead receiver pressure andtemperature, and gasoline endpoint all

influence the amount of wet gas and itsmolecular weight. Variability in maincolumn overhead receiver pressure orunstable system pressure drop producereactor pressure swings. These can causecatalyst circulation problems and otheroperability concerns.

Reactor operating pressure is set bymain column overhead receiver pressureand system pressure drop. System pres-sure drop depends on equipment designand operation, while compressor andcontrol system performance set receiver

pressure. Wet gas compressors operate atfixed or variable speed. Fixed speed com-pressors throttle compressor suctionwhile variable speed machines use steamturbines or variable speed motors tocontrol receiver pressure.

If necessary, compressor surge controlsystems recycle gas to ensure inlet gasflow rate is maintained above the mini-mum flow (surge point or line). Evenwhen receiver pressure is stable, rapidsystem pressure drop changes from trayflooding and dumping will cause rapidchanges in reactor pressure.

Most motor driven compressors oper-ate at fixed speed using suction throttlevalves to vary pressure drop from themain column overhead receiver to thecompressor inlet (Figure 2). The pressurecontroller manipulates the throttle valveposition and pressure drop to maintainconstant receiver pressure. Normal sys-tem pressure drop variation is slow andpredictable. Therefore, receiver pressurecan be adjusted to maintain constantreactor pressure.

As long as the throttle valve is notfully open, then the compressor hasexcess capacity. Once the throttle valveis fully open and spillback valve isclosed, the machine can no longer com-press wet gas flow to the gas plant oper-ating pressure. Generally, reactortemperature or feed rate is reduced to

Centrifugal compressoroperations

The wet gas compressor is used as an example in this article reviewing compressorperformance, operating conditions and basic control philosophy – an aid tounderstanding the interactions influencing compressor performance and control

Tony Barletta and Scott W GoldenProcess Consulting Services Inc

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Figure 1 Regenerator-reactor differential pressure

Figure 2 Fixed speed compressor and inter-condenser system

permit the compressor throt-tle valve to regain pressurecontrol so that flaring can beavoided.

Variable speed compressorsuse steam turbines or variablespeed motors to controlreceiver pressure. Speed isadjusted to change the operat-ing point on the compressormap to meet the system flow-head requirements for stablereactor pressure control. Assystem pressure drop increas-es, receiver pressure is reduced. There-fore, machine speed must be increasedto compress the higher gas flow rate andto meet higher head requirements.

Once the turbine governor is wide-open or the variable speed motor isoperating at maximum speed or amps,feed rate or reactor temperature must bereduced to lower wet gas rate to thecompressor capacity.

Fixed or variable speed motors andturbines must have sufficient power tocompress the mass flow rate of gas whilemeeting the differential head betweenthe overhead receiver and the gas plant.Otherwise, reactor temperature or feedrate must be reduced to decrease theamount of receiver wet gas flow to thedriver limit.

Compressor DesignWet gas machines use six to eightimpellers (stages) to compress gas fromthe main column overhead receiver tothe gas plant operating pressure. Mosthave inter-stage condensing systemsafter the first three or four stages (low-stage) that cool the compressed gas, con-dense a small portion and separate thegas and liquid phases (Figure 3). Inter-stage receiver gas is then compressed inthe last three or four stages (high-stage).Inter-stage condensers reduce gas tem-perature and raise compressor effi-ciency by 5–7%, but they alsoconsume pressure drop. Separateflow-polytropic head and flow-polytropic efficiency curves areneeded to evaluate overall com-pressor system performance.

These curves have inlet gasflow rate on the X-axis and poly-tropic head developed and poly-tropic efficiency on the Y-axis.Consequently, overall compressorperformance and power con-sumption depend on each com-pressor section’s performancecurves and the effects of the inter-condenser system. Evaluatingoverall performance of these com-pressors is more complex than amachine without inter-cooling,but fundamentally the same.

Some compressors do not have

inter-condenser systems. A single flow-polytropic head and flow-polytropicefficiency curve represent overallperformance. They have lower efficien-cy and the gas temperature leaving isgenerally near 300°F rather than 200°Fwith an inter-cooled design. Thesemachines must compress all wet gasfrom inlet conditions to the gas plantoperating pressure, resulting in higherpower consumption.

Stable operating range Each wet gas compressor section mustbe operated within its stable flow range.At fixed speed, the compressor curvebegins at the surge point and ends atstonewall, or choke flow. Surge point isan unstable operating point where flowis at minimum. At surge, the compressorsuffers from flow reversals that causevibration and damage. At the other endof the curve is the choke (or stonewall)point. At the choke point, the inlet flowis very high and the head developedvery low. Flow through the machineapproaches sonic condition, or Mach1.0. Polytropic efficiency also dropsrapidly near stonewall.

For variable speed compressors, thereis a region between the surge andstonewall lines where there is stablemachine performance (Figure 4). The

compressor flow-polytropichead can be varied anywherewithin this region. Becausethere is no throttling, allpower goes into compression,which minimises power con-sumption.

Stable compressor perform-ance is defined between thesetwo flow-head limitations.Some machine designs canvary flow by 25% or morebetween surge and stonewallpoints, while others have

only 6–8% flow variation between theselimits. Compressors with small (narrow)stable flow regions need to have robustsurge control systems. The head-flowcurve basic slope is relatively flat nearthe surge point and becomes steeper asinlet flow is increased. The impellerblade angle determines the shape of thecurve and the compressor efficiency.

Basic compressor controlReactor yield and condenser operatingtemperature and pressure changethroughout the day. Therefore, the gasrate from the main column receiver isvariable. Consequently, the compressorcontrol system must be capable of main-taining constant receiver pressure. Thus,fixed speed compressors have suctionthrottle valves and variable speedmachines change speed to compensatefor gas rate changes. Because the com-pressor inlet gas flow rate is not constantand may be below the surge point orline, the compressor is typicallydesigned with a surge control system.

Surge control ensures that inlet flowrate is maintained above minimum(surge point or surge line) at all times. Aflow meter in the compressor suction ordischarge and inlet temperature andpressure are used to calculate the actualflow rate (ICFM) into the low- and high-

stage of compression. As suction flow (ICFM) decreas-

es toward the surge line (or point),the spillback control valve opensto recycle gas from discharge tosuction to raise inlet flow rate.Spillback flow is kept at minimumto reduce power consumption.Compressors with inter-con-densers need two independentspillback systems from dischargeto the suction of each section.Spillback streams should be routedin front of upstream exchangers sothe heat of compression isremoved (Figure 2).

Without inter-condenserThe simplest wet gas compressorto evaluate is a fixed speedmachine with no inter-con-densers. It has a single flow-head

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Figure 3 Compressor schematic with inter-condenser

Figure 4 Variable speed flow-head map

curve (and single flow-efficiency curve)with surge point rather than a line.

Although molecular weight doesaffect developed head, typical molecularweight variations in a gas oil cracker donot materially change compressor flow-head performance curve. Whereas, residcrackers processing varying amountsand quality of residues may have asmuch as eight number variations inmolecular weight, thus the flow-headperformance curve is affected. The man-ufacturer should provide curves at max-imum and minimum molecular weight.

Figure 5 is the performance curve fora six-stage FCC wet gas compressor thatis also discussed in this article’s casestudy. The compressor develops a fixedpolytropic head for a given inlet flowrate and the curve can be used to predictcompressor performance at differentprocess conditions.

The suction throttle valve plays animportant role for a fixed speed motordriven compressor. Throttle valve pres-sure drop controls overhead receiverpressure (Figure 6) so that reactor pres-sure is stable. Throttle valve positionand pressure drop compensate forchanges in receiver gas flow rate orreceiver pressure set point changes.Because compressor discharge pressureis held constant by the gas plant pres-sure controller, suction pressure willvary and follow the flow-head curve.

When gas rate leaving the overheadreceiver is higher than flow at the surgepoint, the spillback is closed. Hence,compressor suction pressure will ride upand down the flow-head curve as long asthe throttle valve is generating pressuredrop and not fully open. As compressorinlet flow rate approaches the surgepoint, the spillback valve opens recy-cling gas to ensure sufficient inlet flowinto the machine. When the spillback isopen, spillback flow rate determines theoperating point on the curve. Flow ratemust always be maintained above thesurge point with suction pressure deter-

mined by the polytropic head generatedat the minimum flow control point.

Since the amount of gas leaving theoverhead receiver depends on reactoreffluent composition and overheadreceiver conditions, the compressor suc-tion pressure will vary. As previously dis-cussed, the compressor has unusedcapacity as long as the suction throttlevalve is not fully open.

When establishing operating condi-tions to stay within an existingmachine’s capacity, or if considering arevamp, determining the compressorsuction pressure needed to meet the pro-posed operation is critical. Compressorsuction pressure is calculated from thecompressor performance curve. Becausethe flow and head terms are affected bysuction pressure, estimating this pres-sure is an iterative process.

Centrifugal compressors generate afixed polytropic head (and not a fixeddischarge pressure) at a given inlet flowrate – with suction pressure, gas molecu-lar weight and gas temperature all influ-encing both inlet flow rate andpolytropic head. The polytropic headequation is shown in Equation 1 below.where

MW Molecular weightZavg Average compressibilityT1 Suction temperature, °Rn Compression coefficientP1 Suction pressure, psiaP2 Discharge pressure, psia

Understanding each variable’s impacton inlet flow rate and polytropic head isimportant. Molecular weight and suc-tion pressure have a significant influ-ence on performance, while compressordischarge pressure (P2) is fixed and tem-perature effects are small. Gas molecularweight (MW) is primarily controlled by

reactor effluent composition. As molec-ular weight decreases the inlet flow rateincreases. Because the compressor dis-charge pressure is fixed, compressor suc-tion pressure must be high enough togenerate the head corresponding to theinlet flow rate into the compressor.

Again, for a fixed speed compressor,as long as the compressor throttle valveis not fully open, it has unused capacity.Thus, molecular weight changes simplycause throttle valve position and pres-sure drop to adjust, to maintain receiverpressure. But once the throttle valve isfully open, the machine is operating atmaximum capacity.

Inlet gas temperature has little influ-ence on compressor capacity because itis based on absolute temperature.Hence, a 20°F rise in temperaturechanges the head term by only 3% andthe flow term a similar amount.

Compressor suction pressure has alarge influence on inlet gas flow rate. Fora fixed mass flow rate, raising suctionpressure decreases inlet volume by theabsolute pressure ratio. At constantreceiver pressure, compressor inlet pres-sure is determined from the flow-headcurve for a fixed speed compressor.Using the compressor curve shown onFigure 5, the suction pressure will bethat needed to satisfy the inlet flow andhead term simultaneously. Throttlevalve pressure drop will vary to main-tain inlet flow rate between 10 400 and11 100icfm, while meeting the gas plantdischarge pressure.

As long as the receiver gas flow rate isabove the surge point, then the spillbackvalve will be closed. However, as gasflow approaches surge, the spillbackvalve opens to maintain flow in a stableregion of the curve. Suction pressure is adependent variable as long as the throt-tle valve has pressure drop. Once thecontrol valve is wide open, the gas ratemust be reduced or the suction pressureincreased to reduce the inlet volumeinto the compressor.

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Figure 5 Flow-head curve for a six-stage compressor Figure 6 Receiver pressure control: compressor suction throttling

Variable speed compressors have anoperating region between the surge andstonewall lines as previously illustratedin Figure 3. Because variable speedcompressors do not incorporate a throt-tle valve, main column overhead receiv-er pressure controller varies speed tomaintain receiver pressure. As long asthe receiver gas flow rate is above thesurge line flow rate, there will be nospillback. However, if receiver gas flow isbelow the surge line, then the spillbackwill open to meet the minimum flow. Inthe previous Figure 3, maximum com-pressor capacity occurs when the com-pressor is operated at maximum speed.As long as the compressor driver hadsufficient energy, then minimum over-head receiver operating pressure will bebased on the flow-head developed at110% of the rated speed for the curveshown in Figure 3.

Capacity: driver powerCompressor power consumption is afunction of the mass flow, polytropichead, polytropic efficiency, and gearlosses. Compressor shaft horsepower(SHP) is shown in Equation 2 below:

Compressor SHP = [(mHρ)/(nρ 33000)] 1.02

whereHρ Polytropic headm Mass flow rate of gasnρ Polytropic efficiency 1.02 2% gear lossesSHP Shaft horsepower.Unlike variable speed compressors,

fixed speed compressors have suctionthrottle valves to control overheadreceiver pressure. Satisfying the flow-head curve requires pressure drop acrossthe control valve and throttling alwayswastes energy. Because variable speedcompressors change speed to match theprocess flow-head requirements, theyconsume less energy. However, the capi-tal cost of steam turbines or variablespeed motors is higher than a fixedspeed motor.

With inter-condenserFigure 3 is a schematic of a six-stagecompressor with three-stages (low-stage)in front and three-stages (high-stage)behind the inter-condenser. Gas muststill be compressed from the overheadreceiver pressure to the gas plant operat-ing pressure. However, the low-stage dis-charges intermediate pressure gas(65–90psig) to an inter-condenser whereit is cooled from approximately 200°F to100–130°F, depending on whether air orcooling water is used. The condenseroutlet stream is sent to a separator drumwhere the gas and liquids (oil and water)are separated. Inter-stage drum gas is fedto the high-stage section of the com-pressor. Each section has its own flow-

polytropic head and flow-polytropicefficiency curves.

Because the inter-condenser systemcondenses a portion of the low-stagegas, mass rate and gas molecular weight(typically four to five numbers lowerthan main column overhead receivergas) is lower into the high-stage. Thisreduces compressor power consumptionand allows for more efficient compres-sor design. Because the low-stage andhigh-stage sections have separate oper-ating curves, each requires an indepen-dent surge control system. One part ofthe compressor may be operating withspillback to avoid surge, while the othermay have the spillback closed.

Fixed speed compressors with aninter-cooler have a suction throttle valvein the low-stage to control main columnoverhead receiver pressure while high-stage discharge pressure is controlled bythe gas plant sponge absorber or aminecontactor pressure controller. Typically,there is no throttle valve in the suctionline to the high-stage. Consequently,discharge pressure from the low-stageand suction pressure to the high-stageare dependent variables.

Inlet flow rate into the low- and high-stages must always be above the surgepoint. Separate spillback systems fromthe low-stage discharge to inlet of themain column condensers and from thehigh-stage discharge to the inlet of theinter-condenser maintain flow abovesurge for both compressor sections. Thus,suction and discharge pressure from thefirst three-stages and suction and dis-charge pressure from the last three-stagesare dependent on each other, inter-con-denser system pressure drop, and theamount of material condensed.

While principles of compression arethe same, overall performance is moredifficult to evaluate. Fortunately, processflow models, such as Simsci’s propri-etary ProII or Provision, allow the low-and high-stage flow-polytropic headcurves and flow-polytropic efficiencycurves, and the inter-condenser system,to be rigorously modelled. Thus, inter-stage operating pressures can be deter-mined through an iterative processwithout excessive calculations.

Case studyMinimising compressor modificationsAn FCC unit was revamped to increaseunit capacity by 40%. In addition, gasplant limitations required undercuttinggasoline to produce heavy naphthafrom the main fractionator to reduceliquid loading through the gas plant.The existing compressor was a seven-stage machine with no inter-condenserand a 4400 horsepower motor. A suctionthrottle valve controlled main fractiona-tor overhead receiver pressure.

Prior to the revamp, reactor pressurewas 20psig with a compressor inlet pres-sure of approximately 4-5psig. The 40%higher feed rate and higher gas fromundercutting, together, would haveincreased inlet flow rate by more than50% if the 4psig suction pressure wasmaintained. Thus, a new parallel com-pressor or one new larger compressorwould have been required. Because thissolution was high cost, alternatives wereconsidered.

When evaluating compressor perfor-mance, the complete system from thereactor through the compressor outletneeds to be evaluated as a single system.Undercutting gasoline increases wet gasflow rate if no other changes are madebecause it decreases the amount of liq-uid product from the main columnoverhead receiver. Gasoline “sponges”C3+ hydrocarbons leaving the con-denser. Therefore, undercutting reducessponging at fixed receiver temperatureand pressure. For example, undercutting10% of the gasoline raises wet gas flowrate by approximately 5–7%. As the per-cent undercutting increases, so does theamount of wet gas from the overheadreceiver.

Increasing mass flow rate through thecompressor without large changes in theinlet flow rate requires higher suctionpressure. System pressure drop from thereactor to the compressor inlet must bereduced. In this case, the reactor pressureoperated at approximately 20psig and thesystem pressure drop was 16 Psi, resultingin a 4psig compressor suction pressure.

High pressure-drop componentsincluded reactor line coke formation,main column overhead system and col-umn internals pressure drop. Table 1shows each major component and itsmeasured pressure drop. Substantialreduction in system pressure drop wasrequired to lower compressor inlet flowrate to within 10400 to 11200 inlet cubicfeet per minute stable operating range.

Increasing compressor suction pres-sure raises condensation in the overheadreceiver, decreases inlet flow rate andincreases compressor capacity. In thisinstance, main column overhead receiv-er pressure and temperature needed to

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Components ∆P, psi

Reactor cyclones 2Reactor vapour line 1Reactor line coke 4Main column 3Condenser 3Piping 2Flow control/metering 1Total 16

Table 1

Reactor system pressure drop

be 12psig and 100°F to main-tain inlet flow rate within sta-ble operating range. Cokingin the reactor line, main col-umn pressure drop, piping,flow metering, and condenserpressure drop all had to bereduced. Otherwise, a newparallel compressor wouldhave been needed.

Overhead condenserexchanger surface area, cool-ing water (CW) flow rate, andCW temperature all influencewet gas flow rate. Each 1°Freduction in receiver temper-ature lowers wet gas rate byapproximately 1%. Thus,decreasing temperature by10°F lowers the wet gas rateby about 10%. Although temperaturehas little effect on gas volume, main col-umn overhead receiver temperature hasa large impact on condensation. Cost-effective changes that reduce receivertemperature should always be consid-ered to maximise existing compressorcapacity or to minimise modifications.

In this instance, raising receiver pres-sure from 5 to 12psig and lowering tem-perature to 100°F decreased the amountof wet gas produced so that the gas inletflow rate was within the existing com-pressor capacity. Raising compressorinlet pressure (and lowering temper-ature) decreased inlet flow rate, but italso raised compressor discharge pres-sure. Since centrifugal compressorsdevelop fixed polytropic head, dischargepressure (P2 in Equation 1) from theexisting seven stages of compressionwould have been 350psig, whichexceeded the maximum allowable work-ing pressure (MAWP) of the majorequipment in the gas plant. Hence,compressor head had to be reduced.

Compressor power requirements alsohave to be considered. Both the flow-head and flow-polytropic efficiencycurve is needed to evaluate power con-sumption. Power requirement wouldhave been more than 5100hp due to the

higher mass flow rate. Hence, the exist-ing 4400hp motor would have to bereplaced. Replacing a motor or steamturbine can be very costly because itoften requires major utilities systemmodifications. Although the compressorOEM or compressor expert should docomprehensive compressor analyses, therevamp engineer can perform prelimi-nary review by making simplifyingassumptions such as equal head rise perstage of compression to determinewhether removing a stage of compres-sion or trimming the impellers is needed.

In this instance, the seven-stage com-pressor developed about 9500ft of headrise per stage of compression. Therefore,eliminating a stage would reduce devel-oped head by about 9500ft. Becausecompressor discharge pressure needed tobe approximately 210psig to meet gasplant operating pressure and to staybelow the 250psig pressure relief valve(PSV) settings, the required polytropichead at 12psig suction and 210psig dis-charge pressure was approximately46 000ft of head. Thus, de-staging was apractical solution. Figure 8 shows thecomparison between the flow-headcurves for the original seven-stagemachine and a de-staged six-stage com-pressor generated by the OEM.

Compressor drivers mustalso be able to supply thepower requirement through-out the stable operatingrange of the compressor.Power consumption dependson mass flow rate throughthe machine, polytropic headdeveloped and compressorpolytropic efficiency. Flow-polytropic efficiency curvesare supplied by the manufac-turer and allow power con-sumption throughout thestable flow range to be easilycalculated. Figure 9 shows acomparison between thepower requirements of aseven- and six-stage compres-sor. By eliminating one stage

of compression, machine horsepowerrequirements were reduced below theexisting 4400hp motor.

Centrifugal machines are used inmany refinery units to compress gases.The principles of compression are thesame irrespective of the process units.Only the gases compressed and the pro-cess variables are different. Understand-ing centrifugal compressor flow-headand flow-efficiency curves is an essentialwhen evaluating process changes orwhen revamping.

Tony Barletta is a chemical engineer withProcess Consulting Services in Houston,Texas, USA. His primary responsibilities areconceptual process design (CPD) and pro-cess design for refinery revamps. He holds aBS degree in chemical engineering from theLehigh University.E-mail: tbarletta@revamps.comScott W Golden is a chemical engineer withProcess Consulting Services. His previousexperience includes refinery process eng-ineering and distillation troubleshooting anddesign. He has written more than 80 techni-cal papers on revamping, trouble-shooting,and distillation. He holds a BS degree inchemical engineering from the University ofMaine. E-mail: sgolden@revamps.com

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Figure 7 Receiver operating pressure: before and after revamp

Figure 8 Flow-head curve for seven- and six-stage compressor Figure 9 Flow-power requirements for 7- and 6-stage compressor