trsharpe23
Chemical
Does an increase in temperature on the suction side of a centrifugal compressor drive the compressor towards the surge region if the discharge pressure of the compressor remains relatively constant? And if so why?
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Suction temperature effects on centrifugal compressors
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EmmanuelTop
Chemical
What gas do you compress? Is it FCC wet gas compressor, or something else?
Look at the equation for the polytropic head of centrifugal compressor.
How does the increase in temperature affects molecular weight and density of gas?
If suction pressure is constant and you are compressing multicomponent vapor phase (in equilibrium with vessel liquid), than the molecular weight of gas increases and moves the compressor towards surge region.
Look at the equation for the polytropic head of centrifugal compressor.
How does the increase in temperature affects molecular weight and density of gas?
If suction pressure is constant and you are compressing multicomponent vapor phase (in equilibrium with vessel liquid), than the molecular weight of gas increases and moves the compressor towards surge region.
I would expect the opposite affect. If the suction and discharge pressure are constant, but the gas mole weight increases, then the differential head had to decrease. A lower differential head corresponds to a higher flow rate, further away from surge. I was just in a meeting regarding some Penex hydrogen recycle compressors and they were concerned about a low temperature in the high pressure separator. At low temperature, more heavy components drop out in the separator and the gas mole weight drops. At a lower mole weight with a constant differential pressure, the head must increase which corresponds to a reduction in flow and that is when they have surge problems.
In think of it in common sense terms. If I deliver a more dense gas to the suction of my compressor, it will be capable of building more pressure. But if I force the differential pressure to remain constant, I will instead get more flow, thus further from surge. If I deliver a less dense gas to the suction of my compressor, it will not be able to build as much pressure. But, if I force the differential pressure to remain constant, i will instead get less flow, thus closer to surge.
But all of this depends on what gas and how the gas density will change as the temperature changes. If it was an air compressor taking in ambient air, the result would be much different than if it was an FCC wet gas compressor.
In think of it in common sense terms. If I deliver a more dense gas to the suction of my compressor, it will be capable of building more pressure. But if I force the differential pressure to remain constant, I will instead get more flow, thus further from surge. If I deliver a less dense gas to the suction of my compressor, it will not be able to build as much pressure. But, if I force the differential pressure to remain constant, i will instead get less flow, thus closer to surge.
But all of this depends on what gas and how the gas density will change as the temperature changes. If it was an air compressor taking in ambient air, the result would be much different than if it was an FCC wet gas compressor.
EmmanuelTop
Chemical
I apologize, it should have been stated as "moving compressor OPPOSITE from surge region". Lapsus calami.
I assumed it was a wet gas compressor, with wide-range gas composition. In case of increased temperature and constant suction pressure, molecular mass of the vapor phase becomes higher, which results in two possible consequences/demands:
1) Reduction of compressor suction pressure
2) Increasing inlet volumetric flow rate
If compressor is a constant-speed one, suction pressure control or spillback control are employed, to move compressor operating point away from the surge state.
In case of a non-equilibrium gas phase (a single-component or mixture above two-phase region), temperature change has a very little or no effect.
I assumed it was a wet gas compressor, with wide-range gas composition. In case of increased temperature and constant suction pressure, molecular mass of the vapor phase becomes higher, which results in two possible consequences/demands:
1) Reduction of compressor suction pressure
2) Increasing inlet volumetric flow rate
If compressor is a constant-speed one, suction pressure control or spillback control are employed, to move compressor operating point away from the surge state.
In case of a non-equilibrium gas phase (a single-component or mixture above two-phase region), temperature change has a very little or no effect.
EmmanuelTop
Chemical
Here is a part of article by Scott W. Golden, Scott A. Fulton and Daryl W. Hanson, "Understanding centrifugal compressor performance", published in PTQ, spring 2002:
"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 pressuredrop 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 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 flow-head 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.
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 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 18.7psia to 20.7psia decreases the inlet gas flow rate by 10.6 per cent for the same mass flow rate. When the suction pressure is 44.7psia the same 2psi change reduces gas volume by only 4 per cent.
Gas density = P (MW)/RT
where
P = gas pressure (absolute)
T = gas temperature (absolute)
MW = gas molecular weight
R = gas constant.
Increasing gas molecular weight (MW) will also increase gas density and reduce volume for a fixed mass flowrate. Reactor and coke drum effluent composition controls gas molecular weight. FCC dry gas typically has a molecular weight in the range of 21–23. Typical propylene/propane mixtures have a molecular weight of 43.5.
As the FCC reactor reduces the dry gas yield and increases heavier C3 and C4s yield, the wet gas molecular weight and wet gas density increase, thus reducing inlet volume. A 5 per cent increase in gas molecular weight decreases inlet volume flow rate by 5 per cent for a fixed temperature and pressure.
Centrifugal compressors do not develop a constant differential pressure; they develop a constant differential polytropic head at a given inlet flow rate. Often, the compressor curves provided by the E&C company or the compressor vendor will report the performance curve as differential pressure versus inlet flow rate. These differential pressure curves represent one set of inlet operating conditions only. They are not sufficient to evaluate the compressor and connected system performance. Understanding the components of this head term is essential when considering the influence of the process operating pressure and the system pressure drop’s effect on compressor capacity. Reducing polytropic head will increase compressor capacity by moving the operating point to the right except at stonewall. The slope of the curve will determine the magnitude of the inlet flow rate increase resulting from a given polytropic head reduction. Process changes that move the operating point to the right include higher gas molecular weight, raising suction pressure, or lowering discharge pressure. Gas temperature changes have little influence on head."
"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 pressuredrop 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 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 flow-head 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.
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 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 18.7psia to 20.7psia decreases the inlet gas flow rate by 10.6 per cent for the same mass flow rate. When the suction pressure is 44.7psia the same 2psi change reduces gas volume by only 4 per cent.
Gas density = P (MW)/RT
where
P = gas pressure (absolute)
T = gas temperature (absolute)
MW = gas molecular weight
R = gas constant.
Increasing gas molecular weight (MW) will also increase gas density and reduce volume for a fixed mass flowrate. Reactor and coke drum effluent composition controls gas molecular weight. FCC dry gas typically has a molecular weight in the range of 21–23. Typical propylene/propane mixtures have a molecular weight of 43.5.
As the FCC reactor reduces the dry gas yield and increases heavier C3 and C4s yield, the wet gas molecular weight and wet gas density increase, thus reducing inlet volume. A 5 per cent increase in gas molecular weight decreases inlet volume flow rate by 5 per cent for a fixed temperature and pressure.
Centrifugal compressors do not develop a constant differential pressure; they develop a constant differential polytropic head at a given inlet flow rate. Often, the compressor curves provided by the E&C company or the compressor vendor will report the performance curve as differential pressure versus inlet flow rate. These differential pressure curves represent one set of inlet operating conditions only. They are not sufficient to evaluate the compressor and connected system performance. Understanding the components of this head term is essential when considering the influence of the process operating pressure and the system pressure drop’s effect on compressor capacity. Reducing polytropic head will increase compressor capacity by moving the operating point to the right except at stonewall. The slope of the curve will determine the magnitude of the inlet flow rate increase resulting from a given polytropic head reduction. Process changes that move the operating point to the right include higher gas molecular weight, raising suction pressure, or lowering discharge pressure. Gas temperature changes have little influence on head."
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trsharpe23
Chemical
Thanks for the replies.
The gas being pumped is propane (single component therefore constant MW) the suction conditions range across the stages but taking the LP stage, about -40degC and atmospheric pressure.
Problem occurs when running the compressor down i.e. going from 100% operation to full recycle with Anti-surge valve and line situated after the aftercooler (70 degC propane) and rejoining into the suction drum.
The DISCHARGE pressure can be regarded as constant, but suction pressure can vary.
I suppose at this point the compressor is being controlled by the ASV at the surge control line. But the increase in temperature due to the recycled warmer propane gas mixing with the cold suction propane, causes the operating point to move towards the surge region.
However I would also expect an increase in suction pressure side due to an increase in density and hence an increase in capacity, but the opposite is seen in my model.
Was wondering if someone could explain and back this up with operating experience?
The gas being pumped is propane (single component therefore constant MW) the suction conditions range across the stages but taking the LP stage, about -40degC and atmospheric pressure.
Problem occurs when running the compressor down i.e. going from 100% operation to full recycle with Anti-surge valve and line situated after the aftercooler (70 degC propane) and rejoining into the suction drum.
The DISCHARGE pressure can be regarded as constant, but suction pressure can vary.
I suppose at this point the compressor is being controlled by the ASV at the surge control line. But the increase in temperature due to the recycled warmer propane gas mixing with the cold suction propane, causes the operating point to move towards the surge region.
However I would also expect an increase in suction pressure side due to an increase in density and hence an increase in capacity, but the opposite is seen in my model.
Was wondering if someone could explain and back this up with operating experience?
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