Centrifugal compressor operations

The wet gas compressor is used as an example in this article reviewing compressor performance, operating conditions and basic control philosophy

Tony Barletta and Scott W Golden, Process Consulting Services

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Article Summary

The FCC wet gas compressor’s major function is reactor pressure control. The machine must compress gas from the main column overhead receiver to gas plant operating pressure while maintaining stable regenerator-reactor differential pressure (Figure 1). Typically, reactor-regenerator differential pressure must be controlled within a relatively narrow +2.0psi to –2.0psi (+0.14 to –0.14 bar) range to permit stable catalyst circulation. The wet gas compressor and its control system play a vital role in maintaining steady reactor operating pressure. To be sure, optimum FCC operation requires balancing regenerator and reactor pressures to wet gas and air blower constraints. Nonetheless, reactor pressure is presumed constant throughout this article to simplify discussions.

Reactor operating pressure is regu-lated by the main column overhead receiver pressure and system pressure drop from the reactor to the overhead receiver. The wet gas machine needs to have sufficient capacity to compress receiver wet gas to the gas plant operating pressure. Reactor effluent composition, overhead receiver pressure and temperature, and gasoline endpoint all influence the amount of wet gas and its molecular weight. Variability in main column overhead receiver pressure or unstable system pressure drop produce reactor pressure swings. These can cause catalyst circulation problems and other operability concerns.

Reactor operating pressure is set by main column overhead receiver pressure and system pressure drop. System pressure drop depends on equipment design and operation, while compressor and control system performance set receiver pressure. Wet gas compressors operate at fixed or variable speed. Fixed speed compressors throttle compressor suction while variable speed machines use steam turbines or variable speed motors to control receiver pressure.

If necessary, compressor surge control systems recycle gas to ensure inlet gas flow rate is maintained above the minimum flow (surge point or line). Even when receiver pressure is stable, rapid system pressure drop changes from tray flooding and dumping will cause rapid changes in reactor pressure.

Most motor driven compressors operate at fixed speed using suction throttle valves to vary pressure drop from the main column overhead receiver to the compressor inlet (Figure 2). The pressure controller manipulates the throttle valve position and pressure drop to maintain constant receiver pressure. Normal system pressure drop variation is slow and predictable. Therefore, receiver pressure can be adjusted to maintain constant reactor pressure.

As long as the throttle valve is not fully open, then the compressor has excess capacity. Once the throttle valve is fully open and spillback valve is closed, the machine can no longer compress wet gas flow to the gas plant operating pressure. Generally, reactor temperature or feed rate is reduced to permit the compressor throttle valve to regain pressure control so that flaring can be avoided.

Variable speed compressors use steam turbines or variable speed motors to control receiver pressure. Speed is adjusted to change the operating point on the compressor map to meet the system flow-head requirements for stable reactor pressure control. As system pressure drop increases, receiver pressure is reduced. Therefore, machine speed must be increased to compress the higher gas flow rate and to meet higher head requirements.

Once the turbine governor is wide-open or the variable speed motor is operating at maximum speed or amps, feed rate or reactor temperature must be reduced to lower wet gas rate to the compressor capacity.

Fixed or variable speed motors and turbines must have sufficient power to compress the mass flow rate of gas while meeting the differential head between the overhead receiver and the gas plant. Otherwise, reactor temperature or feed rate must be reduced to decrease the amount of receiver wet gas flow to the driver limit.

Compressor Design
Wet gas machines use six to eight impellers (stages) to compress gas from the main column overhead receiver to the gas plant operating pressure. Most have inter-stage condensing systems after the first three or four stages (low-stage) that cool the compressed gas, condense a small portion and separate the gas and liquid phases (Figure 3). Inter-stage receiver gas is then compressed in the last three or four stages (high-stage). Inter-stage condensers reduce gas temperature and raise compressor efficiency by 5–7%, but they also consume pressure drop. Separate flow-polytropic head and flow-polytropic efficiency curves are needed to evaluate overall compressor system performance.

These curves have inlet gas flow rate on the X-axis and polytropic head developed and polytropic efficiency on the Y-axis. Consequently, overall compressor performance and power consumption depend on each compressor section’s performance curves and the effects of the inter-condenser system. Evaluating overall performance of these compressors is more complex than a machine without inter-cooling, but fundamentally the same.

Some compressors do not have inter-condenser systems. A single flow-polytropic head and flow-polytropic efficiency curve represent overall performance. They have lower efficiency and the gas temperature leaving is generally near 300°F rather than 200°F with an inter-cooled design. These machines must compress all wet gas from inlet conditions to the gas plant operating pressure, resulting in higher power consumption.

Stable operating range
Each wet gas compressor section must be operated within its stable flow range. At fixed speed, the compressor curve begins at the surge point and ends at stonewall, or choke flow. Surge point is an unstable operating point where flow is at minimum. At surge, the compressor suffers from flow reversals that cause vibration and damage. At the other end of the curve is the choke (or stonewall) point. At the choke point, the inlet flow is very high and the head developed very low. Flow through the machine approaches sonic condition, or Mach 1.0. Polytropic efficiency also drops rapidly near stonewall.

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