Downstream control valves

A weigh tank containing chlorosulfonic acid needed to be cleaned to remove salt deposits. The salt deposits precipitated from the material and occasionally plugged the downstream control valve. Since the material was water reactive, heptane was chosen to clean the vessel. Chemists had not anticipated the material would be reactive with heptane. While cleaning the vessel the pressure... 

When the control valve downstream of a pump is operating in a mostly closed position, the upstream pump is a good candidate to have its impeller trimmed. Sometimes, the pressure drop across a control valve is so huge (>100 psi) that it makes a roaring sound. The energy represented by this wasteful AP is coming from the electricity supplied to the pump s motor. Hence, trimming the impeller also reduces wear because of erosion in downstream control valves. 

For energy exchange equipment Supply sufficient excess of heat transfer area in reboilers, condensers, cooling jackets, and heat removal systems for reactors to be able to handle the anticipated upsets and dynamic changes. Sometimes extra area is needed in overhead condensers to subcool the condensate to prevent flashing in the downstream control valves. Too frequently, overzealous engineers size the optimum heat exchangers based on an economic minimum based on steady-state conditions and produce uncontrollable systems. 

In order for the downstream control valves which control the flow-rate of SOa/air to function in their optimum range and therefore enable the SO3 organic mole ratio to be maintained as constant as possible, the air discharge pressure from the compressors must be controlled. Excess air from the compressors can be vented to atmosphere automatically through a valve controlled by the pressure measured at some point downstream of the venting point. An alternative system of controlling the compressor speed can be used where energy costs justify the additional capital expenditure. 

Installation of a smaller impeller is a simple mechanical procedure. When a motor-driven pump puts up excess head, as indicated by the downstream control valve position, switching to a smaller impeller will significantly cut motor horsepower requirements. Table 9-1 relates the effect of changing impeller size to flow, head, and horsepower. 

The cheapest way to debottleneck a process operation that is limited by a pump is to reduce downstream pressure drop. A detailed hydraulic survey is the key. Do not forget to check the pressure drop across the downstream control valve (see Chapter 9). 

Turbine A turbine uses steam pressure or burning gas to drive pumps and compressors at variable speeds. Motor drives are usually fixed-speed machines. Variable speed is an energy-efficient way to control flows by eliminating the downstream control valve. 

Normally, motor amps increase as a downstream control valve is opened. If you observe the opposite, then the control valve operation will be erratic, because you are attempting to control the flow too far out on the pump s curve. This is another reason why the centrifugal pump and the control valve need to be designed to work together as a team. This is exactly what the commimist engineers in Lithuania failed to do. 

Before any given test, weather data were measured and recorded and the transfer line and receiver tank purged with dry nitrogen gas. The 600 gallon liquid storage tank was pressurized to the predetermined pressure level. Then the hand valve and the downstream control valve were placed in the open position. 

Across a control valve the fluid is accelerated to some maximum velocity. At this point the pressure reduces to its lowest value. If this pressure is lower than the liquid s vapor pressure, flashing will produce bubbles or cavities of vapor. The pressure will rise or recover downstream of the lowest pressure point. If the pressure rises to above the vapor pressure, the bubbles or cavities collapse. This causes noise, vibration, and physical damage. 

When there is a choice, design for no flashing. When there is no choice, locate the valve to flash into a vessel if possible. If flashing or cavitation cannot be avoided, select hardw are that can withstand these severe conditions. The dowmstream line will have to be sized for tw o phase flow. It is suggested to use a long conical adaptor from the control valve to the downstream line. 

It is not a bad idea for the process engineer to familiarize himself with compressor surge controls. The interaction of the compressor surge controls with downstream process control valves can become a problem area later, and this study phase is not too early to put such items on a checklist. An LNG plant example comes to mind where such an operating problem existed. 

The most frequently encountered flashing problems are in control valves. Downstream from the control valve a point of lowest pressure is reached, followed by pressure recovery. A liquid will flash if the low pressure point is below its vapor pressure. Subsequent pressure recovery can collapse the vapor bubbles or cavities, causing noise, vibration, and physical damage. 

When analyzing such individual control valve failures, one should consider the action of other control valves in the system. In the first two cases above, credit may be taken, where applicable for the reduction in pressure of a high-pressure source due to net inventory depletion during the period that the downstream equipment pressure is rising to relieving pressure. However, the pressure relieving facilities must be sized to handle the calculated peak flow conditions. 

When determining pressure rehef requirements, one should calculate capacities of control valves for the relieving conditions of temperature and pressure, since these are in many cases significantly different from capacities at normal operating conditions. Downstream equipment must be analyzed imder relieving conditions. 

If the control valve size is critical to the overpressure protection of the downstream equipment, and must not be increased, then this is clearly noted in all relevant documentation (specification sheets, flow diagram, operating manual, etc.,) and a warning notice plate is welded to the valve body. In such cases, an actual check of the valve installed or purchased should be made during the startup review. 

If there is a bypass around the control valve, downstream equipment must be protected so that its pressure would not exceed the 1.5 Times Design Pressure Rule, considering that the control valve is in the wide open position, and the bypass 50% open. 

Choking, or expansion of gas from a high pressure to a lower pressure, is generally required for control of gas flow rates. Choking is achieved by the use of a choke or a control valve. The pressure drop causes a decrease in the gas temperature, thus hydrates can form at the choke or control valve. The best way to calculate the temperature drop is to use a simulation computer program. The program will perform a flash calculation, internally balancing enthalpy. It will calculate the temperature downstream of the choke, which assures that the enthalpy of the mixture of gas and liquid upstream of the choke equals the enthalpy of the new mixture of more gas and less liquid downstream of the choke. 

Whenever two-phase flow is encountered in facility piping it is usually in flowlines and interfield transfer lines. Some designers size liquid lines downstream of control valves as two-phase lines. The amount of gas involved in these lines is low and thus the lines are often sized as singlephase liquid lines. Oversizing two-phase lines can lead to increased slugging and thus as small a diameter as possible should be used consistent with pressure drop available and velocity constraints discussed in Volume 1. 

The downstream pressure-sensing pipe of each valve is connected to a straight section of pipe 10 diameters or 1 meter downstream of the nearest tee, elbow or valve. This sensing line should be pitched down, to drain into the low-pressure line. If it cannot drain when connected to the top of this line it can often be connected instead to the side of the pipe. The pipe between the two control valves must be drained through a steam trap, just as would the foot of any riser downstream of the pressure-reducing station. 

The choice of a suitable temperature or pressure control valve for steam application will depend on the supply side pressure, the downstream pressure, and the flow rate of steam to be passed. In the case of temperature control valves the first of these is usually known and the third can be calculated, but the appropriate pressure drop through the valve is often to be decided. Sometimes the maker s rating of a heater will specify that it transfers heat at a certain rate when supplied with steam at a certain pressure. This pressure is then the pressure downstream of the control valve, and the valve may be selected on this basis. 

If the pressure drop across the valve is to be more than 42 per cent of the inlet absolute pressure the valve selection is the same as if the pressure drop were only 42 per cent. With this pressure ratio the steam flow through the valve reaches a critical limit, with the steam flowing at sonic velocity, and lowering the downstream pressure below 58 per cent of the inlet absolute pressure gives no increase in flow rate. When the heater needs a higher pressure, or when the pressure required in the heater is not known, it is safer to allow a smaller pressure drop across the control valve. If the necessary heater pressure is not known, a pressure drop across the control valve of 10-25 per cent of the absolute inlet pressure usually ensures sufficient pressure within the heater. Of course, in the case of pressure-reducing valves the downstream pressure will be specified. 

Bends and tee-pieces in pipework often create locally turbulent flow. This enhances the corrosivity of the process liquid. These effects should be minimized by the use of flow straighteners, swept tees and gentle bends. Flow-induced corrosion downstream of control valves, orifice plates, etc. is sometimes so serious that pipework requires lining with resistant material for some twelve pipe diameters beyond the valve. 

The effect of resistances and capacities in the air line and water feed has been studied theoretically and it has been shown that oscillations will tend to be stable if there is a large air capacity downstream from the control valve, and the inclusion of a resistance in the water supply line should dampen them. 

HF is supplied from a 100-Jb cylinder on an electronic scale which has a 10-g resolution. The cylinder is heated to 37°C with a band heater with two integral temperature sensors, one for control and an independent one for shutdown in case of overheating. From the cylinder, the HF passes through a throttling valve, a backup shutdown valve, and a control valve. A continuous nitrogen flow (actually the cathode reference flow) was added downstream of the control valve. 

The whole set-up for partial oxidation comprises a micro mixer for safe handling of explosive mixtures downstream (flame-arrestor effect), a micro heat exchanger for pre-heating reactant gases, the pressure vessel with the monolith reactor, a double-pipe heat exchanger for product gas cooling and a pneumatic pressure control valve to allow operation at elevated pressure [3]. 

It is easy to improperly design a steam trap. The design must work for two circumstances and often a designer will check only one of these. The circumstance often overlooked is as follows On startup or upset, the steam control valve can open wide so that the steam chest pressure (assume for this discussion that we are speaking of a reboiler) rises to full steam line pressure. At a time like this, the steam trap downstream pressure can be atmospheric due to process variations or the operators opening the trap discharge to atmosphere in an attempt to get it working. 

When recycling material to the reactor for whatever reason, the pressure drop through the reactor, separator (if there is one), the heat transfer equipment upstream and downstream of the reactor, control valves, and so on must be overcome. This means the pressure of any material to be recycled must be increased. Again, for the case of a liquid recycle, the cost of this pressure increase is usually small. On the other hand, to increase the pressure of material in the gas phase for recycle requires a compressor and is expensive. 

If very close control is desired, then any disturbance due to steam pressure changes should be minimized. Figure 7-9 shows how this can be done using a cascade control system. In this case, the temperature of the process stream is measured and compared to its desired value, as before. The output of the controller, however, instead of affecting the control valve, regulates the set point of a second controller, the steam-pressure controller. This controller compares the set point determined by the first controller with the pressure downstream of the steam valve. 

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