Compressor

Transcript

REVAMPS Understanding Centrifugal Compressor Performance in a Connected Process System Scott Golden, Scott A. Fulton and Daryl W. Hanson Process Consulting Services Inc., Houston, Texas et gas compressor capacity limits feed rate or unit conversion in many FCC and delayed coker units. Understanding compressor performance and its interaction with the connected process systems is critical when revamping FCC and delayed coker units. Many times unnecessary changes are made to the compressor and driver. Alternatively, lower cost process system modifications can be used to debottleneck a compressor limit. Figure 1 shows a block diagram of a compressor and the connected process system components. The connected process system and compressor performance must be thoroughly evaluated as a single system to determine the most cost-effective way to increase compressor capacity, but conventional process design approaches use several equipment disciplines to evaluate piping, heat exchange, and distillation systems independently. Thus the opportunity to debottleneck the compressor with lower cost process system changes may go unnoticed. Reducing system pressure drop (Table 1) to increase suction pressure or decrease discharge pressure allows more gas to be compressed through the compressor without modifications. However, the impact of suction and discharge system changes on compressor capacity is not the same. Process Equipment Pressure Drop Main Column Internals Piping/Nozzles Control Valves Fin-fans Shell and Tube Exchangers Flow Metering W Suction pressure changes have a much larger influence on compressor capacity due to their effect on overhead receiver condensation, gas density, and compressor head. Connected Process System Table 1. Process system operating pressure and system pressure drop strongly influence wet gas compressor capacity. Compressor discharge and suction pressure are variables and should be manipulated whenever possible to raise compressor capacity. Increasing compressor suction pressure and reducing discharge pressure will increase compressor capacity. Finding cost-effective solutions always starts with field measurements of the current operation to identify high pressure drop components. Distillation column internals, process piping, heat exchangers, control valves, and flow metering in the connected process system must be modeled together with the compressor to quantify compressor capacity increases resulting from equipment modifications. In an FCCU, feed rate, reactor/regenerator differential pressure, and system pressure drop set compressor suction FUEL pressure. In a GAS coker, coke drum constraints and the system pressure OVERHEAD COMPRESSOR CONDENSERS drop set suction CONDENSERS SYSTEM pressure. Discharge pressure is conABSORBER/ MAIN trolled by the gas DEETHANIZER COLUMN plant operating FEED pressure and sysOPERATING PRESSURE tem pressure drop. Practical changes to consider include Figure 1. Compressor and Connected Process System process flow scheme, tower internals, heat exchangers, piping/nozzles, control valves, and orifice plate modifications. These components all generate pressure drop. Process flow scheme changes may include adding a pumparound to the main column or bypassing absorber bottoms liquid around the high pressure condenser to reduce pressure drop. System pressure drop between the main column inlet nozzle and the compressor inlet will vary from a low of 5 to over 25 psi. High pressure drop components need to be identified and cost-effective and reliable changes made. In some instances, replacing main column trayed internals with structured packing will be the low-cost solution. Other times, condenser system pressure drop will control compressor suction pressure. Therefore, piping, fin-fan, shell and tube exchanger, control valve, or flow metering modifications will need to be considered. Absorber operating pressure and system pressure drop set the compressor discharge pressure (Figure 1). Lower discharge pressure reduces compressor head and driver power, which increases compressor capaci- Reprinted from Petroleum Technology Quarterly® Spring 2002 Issue REVAMPS TO INTERSTAGE CONDENSER TO HIGH PRESSURE CONDENSER POLYTROPIC HEAD, FEET 29,000 7,700 RPM 28,000 27,000 26,000 25,000 24,000 23,000 11,500 FROM OVERHEAD RECEIVER FROM INTERSTAGE RECEIVER LOW STAGE HIGH STAGE DRIVER (MOTOR OR STEAM TURBINE) 12,000 12,500 13,000 13,500 14,000 14,500 COMPRESSOR VOLUMETRIC FLOW, ICFM Figure 2. Compressor Block Diagram ty. Discharge pressure should be minimized without reducing gas plant performance. Absorber pressure controls C3 recovery assuming other process variables have been optimized. In a few instances, reducing absorber operating pressure will not materially change C3 recovery. In most cases, however, propylene recovery drops as pressure is reduced and it is not a costeffective way to increase compressor capacity. If the existing compressor discharge system has high pressure drop, then equipment changes may be an effective means to debottleneck the compressor. Typically, compressor discharge pressure will need to be reduced by at least 20 psi to have a meaningful effect on compressor capacity and driver power. Figure 3. Compressor Performance Curve, Low-Stage improves compressor efficiency and reduces the gas temperature rise through the stages of compression. Inter-cooled compressors will have a low-stage curve defining performance upstream of the inter-cooler and a high-stage curve for the downstream portion (Figure 2). In reality, the low (Figure 3) and high-stages (Figure 4) will have 3-4 actual wheels having their own individual performance curves. These low and high-stage performance curves are a composite of the individual stage (Figure 5) curves. Usually these low and high-stage curves are sufficient to evaluate compressor performance and the connected process system’s influence on compressor capacity. Centrifugal compressors have performance curves similar to pumps. The major difference is that a compressor moves gas which is compressible, while the pump moves liquid that is not compressible. The compressor curve flow term is always based on inlet conditions; consequently inlet gas density influences volumetric flow. Flow is shown on the X-axis and head on the Y-axis. For a fixed speed, the curve shows that for a known inlet flow rate a fixed head is developed. Centrifugal compressor inlet flow rate increases as the head decreases. Gas plant operating pressure, connected system pressure drop, and gas composition sets the developed head. Increasing suction pressure, decreasing gas plant operating pressure and/or decreasing process system pressure drop will increase inlet flow rate as long as the compressor is not operating at choke flow. A compressor curve starts at the surge point and ends at stonewall, or choke flow. The surge point is the head at which inlet flow is at its minimum. At this point, the compressor suffers from flow reversal, which is a very unstable operation that is Compressor Fundamentals Most FCC and delayed coker wet gas compressors have an inter-cooler system that 28,000 POLYTROPIC HEAD, FEET 26,000 24,000 22,000 20,000 18,000 16,000 2,800 7,700 RPM LOW STAGE HIGH STAGE SUCTION 3,000 3,200 3,400 3,600 3,800 4,000 4,200 INTERCONDENSER SYSTEM DISCHARGE VOLUMETRIC FLOW, ICFM Figure 4. Compressor Performance Curve, High-Stage Figure 5. Compressor Stages Reprinted from Petroleum Technology Quarterly® Spring 2002 Issue REVAMPS accompanied by vibration and possible damage. On the other end of the curve is the choke (or stonewall) point. At the choke point, the inlet flow through the compressor cannot increase no matter what operating changes are made. Therefore, the range of compressor performance is defined between these two flowhead limitations. Typically, the curve is flat near the surge point and becomes steeper as flow is increased. Hence, small head changes near the surge point cause a large increase in compressor capacity. As compressor operation moves toward stonewall, decreasing head has less influence on inlet flow rate because the curve slope increases. As the stonewall point is approached, changes in head will have negligible effect on inlet flow rate. and coke drum effluent composi7,700 RPM 28,000 tion controls gas molecular weight. 27,000 REDUCED FCC dry gas typiHEAD cally has a molecu26,000 lar weight in the 1,500 FT HEAD range of 21-23. 25,000 Typical propy6% lene/propane mix24,000 tures have a molecular weight 23,000 of 43.5. As the FCC 11,500 12,000 12,500 13,000 13,500 14,000 14,500 reactor reduces the VOLUMETRIC FLOW, ICFM dry gas yield and increases heavier Figure 6. Compressor Performance Curve, Head Reduction C3 and C4’s yield, magnitude of the inlet flow rate increase the wet gas molecular weight and wet gas resulting from a given polytropic head density increase, thus reducing inlet volreduction. Process changes that move the ume. A 5% increase in gas molecular operating point to the right include higher weight decreases inlet volume flow rate by gas molecular weight, raising suction pres5% for a fixed temperature and pressure. sure, or lowering discharge pressure. Gas temperature changes have little influence Compressor Head on head. Compressor molecular weight is Centrifugal compressors do not develop a set by the coke drum or FCC reactor gas constant differential pressure; they develcomposition. Suction pressure changes of op a constant differential polytropic head 5 psi or higher can also influence gas comat a given inlet flow rate. Often, the composition and molecular weight through the pressor curves provided by the E&C comimpact of condensation. pany or the compressor vendor will report Compressor suction and discharge presthe performance curve as differential pressure both influence the polytropic head. sure versus inlet flow rate. These differenCompressor discharge pressure is set by tial pressure curves represent one set of the gas plant operating pressure and the inlet operating conditions only. They are pressure drop from the compressor disnot sufficient to evaluate the compressor charge to the absorber pressure control and connected system performance. valve. For instance, compressor discharge Understanding the components of this and suction pressures of 220 psig and 10 head term is essential when considering psig, respectively, are common. Therefore, the influence of the process operating the pressure ratio term is 234.7 psia/24.7 pressure and the system pressure drops psia or 9.5. Reducing head requires a effect on compressor capacity. Equation 2 decrease in the pressure ratio term. This shows the polytropic head term. simplified evaluation ignores the influence Reducing polytropic head will increase of the inter-stage system. Equation 2. Understanding how discharge and suction pressure influence the polytropic n–1 head term and compressor capacity is the n P2 1,545 n Hp = –1 ZAVGT1 key to evaluating potential connected pron–1 P1 MW cess system modifications. Figure 6 repreWhere: sents the influence of a 1500-foot head Polytropic head, ft Hp reduction on compressor inlet flow rate for MW Molecular weight ZAVG Average compressibility one compressor. Increasing suction presSuction temperature, °R T1 sure P1 or decreasing discharge pressure n Compression coefficient P2 will reduce head. Quantifying the sucP1 Suction pressure, psia Discharge pressure, psia P2 tion and discharge pressure changes that result in the same polytropic head reduccompressor capacity by moving the opertion is useful. Either increasing suction or ating point to the right except at stonewall. decreasing discharge pressure can be used The slope of the curve will determine the to reduce polytropic by 1500-feet and POLYTROPIC HEAD, FEET Compressor Inlet Flow The performance curve flow rate is based on suction conditions and expressed as inlet cubic feet per minute (ICFM). It is not standard gas flow metering units. Wet gas is a compressible fluid, therefore changes in compressor suction conditions that increase gas density will reduce wet gas volumetric flow rate and free up compressor capacity. Gas density is a function of temperature, pressure, and gas molecular weight. Gas density is calculated from the ideal gas law shown in equation 1. For a fixed mass flow Equation 1. Gas Density = P(MW)/RT P = Gas pressure (absolute) T = Gas temperature (absolute) MW = Gas molecular weight R = Gas constant rate and gas composition, temperature has a small effect on gas density because the temperature term is very large. Conversely, increasing compressor suction pressure will significantly increase gas density and reduce the gas volume. The lower the suction pressure the larger the effect of pressure changes on compressor capacity. For example, increasing pressure from 18.7 psia to 20.7 psia decreases the inlet gas flow rate by 10.6% for the same mass flow rate. When the suction pressure is 44.7 psia the same 2 psi change reduces gas volume by only 4%. Increasing gas molecular weight will also increase gas density and reduce volume for a fixed mass flow rate. Reactor Reprinted from Petroleum Technology Quarterly® Spring 2002 Issue REVAMPS WET GAS PRODUCTION, ICFM MAIN FRACTIONATOR VAPOR WET GAS COMP. STRIPPER VAPOR 15,000 PRIMARY ABSORBER BOTTOMS 12,000 9,000 9 10 11 12 OVERHEAD RECEIVER PRESSURE, PSIG RECEIVER TEMPERATURE=100°F 13 COMP. DRIVER PRIMARY ABSORBER FEED OVERHEAD RECEIVER INTERSTAGE RECEIVER HIGH PRESS. RECEIVER Figure 8. Suction Pressure vs. Wet Gas Production WET GAS PRODUCTION, ICFM STRIPPER/ DEETHANIZER FEED 18,000 15,000 12,000 100 110 120 130 140 OVERHEAD RECEIVER TEMPERATURE, °F RECEIVER PRESSURE=8.5 PSIG PRIMARY ABSORBER LIQUID FEED Figure 7. Compressor and Connected System increase the compressor inlet flow capacity by 6%. Suction pressure changes have a much larger influence on compressor capacity than discharge pressure changes. Raising suction pressure by 2.0 psi decreases the head by 1500-feet as a result of reducing the pressure ratio term from 9.5 (234.7/24.7) to 8.8 (234.7 psia/26.7 psia). The compressor discharge pressure would have to be lowered from 220 psig to 202 psig (P2/P1=216.7 psia/24.7 psia =8.8) to produce the same head reduction. Reducing gas plant operating pressure reduces propylene recovery and an 18 psi operating pressure reduction is generally not feasible. On the other hand, it may be possible to reduce system pressure drop by 18 psi. Suction pressure changes of 2 psi, however, are practical on many units. Figure 9. Suction Temperature vs. Wet gas Production amount of condensation that occurs. Compressor suction pressures and temperatures vary from 1.5 to 30 psig and 80°F to 135°F, respectively. Main fractionator pressure and temperature can be optimized through equipment changes. Figures 8 and 9 show the effect of pressure and temperature on wet gas rate for one unit. A low-capital revamp may involve replacing the 4-tube row fin-fan bundles with 6-row bundles. The 6-tube row bundles will have less than half the pressure loss of the 4-tube rows and add surface area that can lower receiver temperature. In one instance, this raised compressor capacity by over 20% by increasing receiver pressure by 2 psi and reducing temperature by 10°F. Three revamp examples will highlight the relationship between the connected process system pressure drop, compressor performance curves, and wet gas compressor capacity. flow rate. When the drivers are limited the turbine steam rate and speed or the motor amps are at maximum. Compressor driver power consumption is a function of the mass flow, compressor polytropic head, compressor efficiency, and gear efficiency. Compressor shaft horsepower (SHP) is shown in Equation 3. Reducing polytropic head lowers the compressor shaft horsepower. Unit Operations Wet gas compressors increase the system operating pressure so that C3-C12 hydrocarbon components can be recovered as liquid product. Compressor system operating suction and discharge pressure will vary depending on reactor/regenerator, coke drum, gas plant, compressor, and/or upstream equipment design and operation. The compressor takes suction from the main column overhead receiver or downstream knockout drum, which operates at 1.5-30 psig and discharges to a gas plant absorber/deethanizer system operating at 160-240 psig. (Figure 7) Main column overhead receiver temperature and pressure determine the amount of wet gas production for a fixed reactor effluent or coke drum composition. Increasing compressor inlet pressure and/or decreasing temperature reduces the wet gas mass flow rate by changing the Compressor Capacity: Driver Power Compressor driver power requirements can also limit the compressor maximum Equation 3. Compressor SHP = (m) Hp/[(np) 3300] 1.02 SHP HP m np 1.02 Shaft horsepower Polytropic head Mass flow rate of gas Polytropic efficiency 2% gear losses EXAMPLE 1: Increasing Compressor Suction Pressure Using Structured Packing A 50,000-bpd unit was revamped to increase capacity to 65,000 bpd. Wet gas compressor capacity was one of the major unit limits. Revamping the compressor, installing a new parallel compressor, or Reprinted from Petroleum Technology Quarterly® Spring 2002 Issue REVAMPS MAIN COLUMN 14.0 MAIN COLUMN 18.0 ATMOSPHERE 20.0 22.0 10.5 10.0 ATMOSPHERE 20.0 22.0 14.5 14.0 WET GAS COMPRESSOR AIR 32.0 19.0 WET GAS COMPRESSOR AIR 19.0 TRAY P=5.0 PSI 32.0 PACKING P=1.0 PSI = PSIG OIL FEED = PSIG OIL FEED AIR BLOWER Figure 10. Main Column with Trays Pressure Profile reducing connected system pressure drop were all evaluated and cost estimates generated for each option. Compressor performance curves, driver horsepower, and connected system pressure drop were all thoroughly studied. Compressor modification required changes to the compressor internals, motor replacement, new motor control center gear, and substation modifications. A new parallel compressor was very expensive and increased operating complexity. Reducing system pressure drop was the least-cost option. Compressor suction pressure drop includes the main column, condenser system, and piping. Condenser and overhead system pressure drop were only 3.5 psi. Main column pressure drop was 5 psi, which represented over 60% of the suction system pressure loss. The unit pressure profile is shown in Figure 10. The main column overhead receiver operated at 10.5 Figure 11. Main Column with Packing Pressure Profile sor capacity was one of the revamp limits. A consequence of the heavy naphtha draw is that wet gas production increases as overhead gasoline rate decreases. Prior to the revamp, the compressor was operating at maximum capacity. Unlike example 1, where the main column had high pressure drop, here the column pressure drop was only 2.5 psi. Piping and condenser system represented almost 85% of the total system pressure loss. This emphasizes that accurate field measured pressure drop must be done as part of preparing for any revamp. The overhead system pressure profile shown in Figure 12 had a measured pressure drop of 13 psi. Pressure drop from the fin-fan outlet to the compressor was 10 psi. The revamp replaced the piping downstream of the fin-fans, shell and tube exchanger shell, piping to the overhead receiver, and orifice plate. Compressor inlet pressure was increased from 2 to 7.5 psig. The revamp replaced the trays with structured packing (Figure 11). This reduced column pressure drop to 1.0 PSI. Compressor inlet pressure was increased from 10.5 to 14.5 psig. This increased condensation, increased gas density, decreased compressor polytropic head, and decreased the inlet volume to the compressor. This increased compressor mass flow capacity by over 30% without changes to the compressor or the driver. EXAMPLE 2: Increasing Compressor Suction Pressure, Reduced Piping Pressure Drop A 40,000-bpd unit was revamped to add a heavy naphtha draw and increase unit capacity by 20%. Heavy naphtha contains a large portion of the gasoline sulfur, and the gas plant liquid handling bottlenecks limited unit conversion. Wet gas compres- 15.0 15.0 PIPING 12.0 NEW PIPING 12.0 9.0 INLET NOZZLE 11.0 WET GAS COMPRESSOR 2.0 NEW EXCHANGER SHELL OULET NOZZLE NEW PIPING 9.0 8.5 INLET NOZZLE WET GAS COMPRESSOR 7.5 OULET NOZZLE PIPING 6.0 4.0 FI FI COMPRESSOR SUCTION PRESSURE INCREASED BY 5.5 PSI OPERATING PRESSURE NEW VENTURI OPERATING PRESSURE Figure 12. FCC Measured Pressure Drop Figure 13. FCC Revamp Pressure Drop Reprinted from Petroleum Technology Quarterly® Spring 2002 Issue REVAMPS field test run to gather all the necessary data to calibrate process and equipment models. This was the critical first-step in establishing all significant unit bottlenecks. As part of the test run, the column and overhead system pressure profile was measured with two digital pressure gauges. Pressure readings between any two points EXAMPLE 3: Increasing were taken simultaneously with gauges Compressor Suction accurate to within +/- .01 psi. The unit Pressure, Reduced Fin-fan pressure profile is shown in Figure 14. Pressure Drop Measured overhead system pressure drop A delayed coker unit revamp objective was was 16 psi with 13 psi measured across the to increase capacity by 25%. The unit was fin-fans alone. The pressure drop from the operating at the maximum compressor overhead receiver to the compressor was capacity. If compressor suction pressure 2.5 psi with more than 50% across the oriand temperature were maintained at curfice meter. Hence measured pressure prorent conditions, increasing the gas flow files clearly pinpointed the high pressure rate by 25% would require major compresdrop components. sor and driver modifications at a cost of As noted, modifying the compressor more than $2 MM. Hence, more cost would be very costly. Reducing fin-fan and effective process system changes were orifice plate pressure loss would be a more evaluated. cost-effective alternative. Compressor inlet The study began with a comprehensive pressure could be increased from 13 to 23 psi (Figure 15) with its FI 29.0 resultant benefits. Process system changes from the main column overhead to the com16.0 13.0 30.0 pressor would include a 15.5 new fin-fan bay in parallel to the existing bays, new fin-fan bundles with additional tube row design to COKER lower pressure drop FRACTIONATOR OPERATING and increase surface PRESSURE area, and larger fan motors to raise the air Figure 14. Delayed Coker Measured Pressure Drop rate. Thus, overhead receiver temperature could be maintained at pre-revamp conditions with a 10 psi increase in 29.0 compressor suction FI NEW FIN pressure. In addition, FANS compressor discharge 25.0 23.0 30.0 system condenser pres24.5 sure loss (Figure 1) would be very high at increased gas flow. Discharge system condenser modifications COKER would permit lower FRACTIONATOR OPERATING compressor pressure. PRESSURE These changes would debottleneck the wet Figure 15. Delayed Coker Revamp Pressure Drop gas compressor limit psi (Figure 13). This increased condensation, increased gas density, decreased compressor polytropic head, and decreased the inlet volume to the compressor. This raised compressor mass flow capacity by over 30%. without changes to the compressor or auxiliaries. Increased condensation, increased gas density, decreased compressor polytropic head, and decreased inlet volume to the compressor would be the outcome. This would permit a 25% increase in feed rate without any compressor modifications. The cost would be a fraction of a new compressor. ■ THE AUTHORS Process Consulting Services in Houston, TX. The company specializes in refinery unit revamps. His previous experience includes refinery process engineering and distillation troubleshooting and design. Golden has authored more than 80 technical papers on revamping, troubleshooting, and distillation. He holds a BS degree in Chemical Engineering from the University of Maine and is a registered professional engineer in Texas. Scott W. Golden is a chemical engineer with Scott A. Fulton is a chemical engineer with Process Consulting Services in Houston, TX. He has worked on 10 FCC unit revamps in his current position, where he is responsible for process flow sheet modeling, conceptual design, and detail equipment modeling and design. Fulton previously worked as a process engineer for Coastal Corporation performing revamp and troubleshooting work for its refineries in the US and Caribbean. He has authored several papers on revamping. He holds a BS degree in Chemical Engineering from Texas A&M University. Daryl W. Hanson is a chemical engineer with Process Consulting Services in Houston, TX. His responsibilities include process and equipment design and field troubleshooting. He specializes in all phases of refinery distillation from process simulation through field inspection. Previously he was lead process specialist for Koch-Glitsch Inc. where he was involved with more than 100 column revamps including heavy oils and light-ends recovery towers. Hanson has authored more than 20 technical papers on revamping, troubleshooting, and distillation. He holds a BS degree in Chemical Engineering from Texas A&M University. Reprinted from Petroleum Technology Quarterly® Spring 2002 Issue