Api 521 standard pdf

Consequently, the plate thickness is often less than one inch. As stated in 3. This implies that depressuring to psig is not a requirement for the higher pressure applications. There are also the main header and unit headers and sub-headers going backwards from the flare into towards the protected equipment.

Question1: Is the maximum load calculation based on the maximum operating pressure or on the design pressure?

A lateral is defined as the section of pipe from single source relief device s outlet flange s downstream to a header connection where relief devices from other sources are tied-in. In other words, the relief flow in a lateral will always be from a single source.

In contrast, the relief flow in a header can be from either a single or multiple sources simultaneously. The flow rate through the depressuring valve should be based on the expected pressure upstream of the depressuring valve. Typically, this would be the maximum normal operating pressure. A higher pressure e. API does not have specific guidelines for measures to prevent potential plugging at the outlet of a relief valve in wet liquid propane service. Good engineering practice should include a design which minimizes the potential relief of wet liquid propane, through limiting the services where wet propane is present in a liquid filled system subject to pressure relief, overfilling protection for partially filled equipment, and design of liquid filled system so that the relief valve setting is above the highest hydraulic pressure possible during operation.

The rated capacity of the pressure relief valve not the actual capacity should be used to size the tailpipe and the laterals in the discharge line of the pressure relief device. Common header systems should use the cumulative required capacities of all devices that may reasonably be expected to discharge simultaneously in a single overpressure event see 5.

For example, if a flare knockout drum is sized to remove liquid particles between and microns, this vessel would be too small if the nozzles shear the liquids to particle sizes of about 20 microns.

What are the consequences if the droplet sizes increase above the recommended value? Does this criteria apply to all types of flares? Can I extrapolate Figure 23? Whether the liquid droplets are either smaller than microns to start with or are sheared through the knock out drum nozzle to sizes smaller than microns, they will not adversely affect flare performance or safety if the mass flux and thermal radiation values are within the flare design range since the flare can handle small liquid droplets.

There is a potential for increased thermal radiation fluxes and smoking potential but the effect should be small. The recommended droplet size of to microns is based on experience with pipe flares. Droplets of smaller size would behave similar to combustion of gas. Because some types of flares can accommodate larger droplets of combustible liquids, the vendor should always be consulted regarding the adequacy of a specific flare in burning liquids. The noise level sound power level expressed by Equation 58 is for either the noise due to flow across the pressure relief valve or the noise generated by flow across the discharge pipe outlet wherever the final discharge point is to atmosphere.

The noise calculations presented in Figure 23 are for noise generated during critical flow, and is not intended for use when the flow is not choked, nor should it be extrapolated beyond the values presented.

As the pressure ratio is defined as the absolute static pressure upstream from the restriction e. Yes, provided all of the criteria in B. Others are interpreting that B. Is it necessary to install a relief valve for the FIRE case in a heat exchanger? If the fire scenario is considered for a shell and tube heat exchanger full of liquid should we size the safety valve based on single or two phase equations? As stated in API Std. Appendix B offers an example of a single relief valve protecting several equipment components.

Section B. It does not unconditionally provide guidance on the relief device set point. RP , Section B. The relief valve is usually set at design pressure but consideration should be given to proper blowdown. No, API does not have any minimum volume requirements as to when to exclude an overpressure scenario. It is up to the user to determine whether the internals within the shell-and-tube heat exchanger would result in two phase relief in a fire.

References cited in Section 5. Now when applying this rule we discovered a significant difference in the result depending on the selection of the units, either SI or USC. The root cause of the difference appears to be in the constants C1 and C1, which have a different dimension when the exponent applied to the "total wetted surface" is changed from 0.

Applying the same constants C1 and C2 would result in a significant difference in the calculated Total heat absorption depending on the selected units.

In extreme cases, the state of the controlled fluid can change e. The wide-open capacity of a control valve selected to handle a liquid can, for example, differ greatly when it handles a gas. This becomes a matter of particular concern where loss of liquid level can occur, causing the valve to pass high-pressure gas to a system sized to handle only the vapor flashed from the normal liquid entry.

This is the vapor breakthrough scenario described in 4. Vapor breakthrough across a control valve can result in slug flow and high liquid velocities. The resultant transient loads on the piping shall be taken into account, including the mechanical design and pipe supports. NOTE Locating the relief device closer to the upstream control valve can reduce the amount of pipe support required and can also reduce the size of the relief device.

Reboilers and other process heating equipment are designed with a specified heat input. When they are new or. The required relieving rate is the maximum rate of vapor generation at relieving conditions including any noncondensables produced from overheating less the rate of normal condensation or vapor outflow.

In every case, the designer should consider the potential behavior of the system and each of its components. For example, the fuel or heat-medium control valve or the tube heat flux can be the limiting consideration. To be consistent with the practice used for other causes of overpressure, design values should be used for an item such as control valve size.

If limit stops are installed on control valves, the wide-open capacity, rather than the capacity at the stop setting, should normally be used. However, if a mechanical stop is installed and is adequately documented, use of the limited capacity can be appropriate. In shell-and-tube heat exchange equipment, heat input should be calculated on the basis of clean, rather than fouled, conditions. The inadvertent opening of any valve from a source of higher pressure, such as high-pressure steam or process fluids, should be considered.

This action can require pressure-relieving capacity unless administrative controls, as defined in 3. The relief load should be determined using the maximum operating pressure upstream of the valve and the relieving pressure on equipment downstream of the valve. If the pressure source is a pipeline or a production well, the pressure upstream of the valve may reach the maximum shut-in pressure of the source after a shutdown.

The user should determine whether inadvertent valve opening combined with maximum shut-in pressure in upstream system is a credible relief case. The following applies when a manual or actuated valve is inadvertently opened, causing pressure buildup in a vessel.

The vessel should have a PRD large enough to pass a rate equal to the flow through the open valve; credit may be taken for the flow capacity of vessel outlets that can reasonably be expected to remain open. The manual or actuated valve should be considered as passing its capacity at a full-open position with the pressure in the vessel at relieving conditions.

Volumetric or heat-content equivalents may be used if the manual or actuated valve admits a liquid that flashes or a fluid that causes vaporizing of the vessel contents. It is typical to consider only one inadvertently opened manual or actuated valve at a time, although simultaneous inadvertent opening of multiple valves shall be considered if a common cause is identified e. Automatic control failures are discussed separately in 4.

Check valves are intended to limit reverse flow but these are not an effective means for preventing overpressure by reverse flow because check valves can leak or can fail. This flow. This standard describes the following three reverse flow conditions and when these should be considered.

For example, if a spare pump is being lined up and the discharge valve is opened before the suction valve is opened, the pump suction may pressure up to the operating pump discharge pressure because of check valve seat leakage. Potential overpressure can be avoided by specifying higher design pressures, may be managed using administrative controls, or may be mitigated by providing pressure relief.

If the design includes a PRD, it is up to the user to determine how to size this device. The user is cautioned to see 3. Note that the entire upstream system, including vessels, piping and auxiliary devices e.

For certain rotating equipment such as reciprocating compressors and positive displacement pumps, the user may determine that significant reverse flow through the machinery will not occur. Overpressure due to normal check valve leakage should still be considered.

If a recycle line is installed downstream of such equipment, then significant reverse flow is a potential due to opening of the recycle valve. In most cases, focus should be on prevention of reverse flow. It is important to note that, in addition to overpressure of the upstream system, reverse flow through machinery can damage rotating equipment, potentially causing loss of containment.

Additional means of reverse flow prevention should be provided. Experience has shown that two reverse flow prevention devices in series are typically sufficient to eliminate significant reverse flow when these are tested or internally inspected and maintained to demonstrate reliability. The user might want to consider dissimilar reverse flow prevention devices e.

For two or more check valves in series that are internally inspected and maintained to demonstrate reliability, only normal check valve leakage may be assumed. Complete check valve failure is assumed for all check valves in series that are not inspected and maintained and for a single check valve regardless if it is inspected and maintained.

The following assumptions may be made to estimate the reverse flow through a failed check valve select one :. The severity of reverse flow through these check valves depends on the following:. Therefore, it is the responsibility of the user to determine an appropriate technique for estimating the reverse flow.

Because of potential common mode failures the user is cautioned against taking a larger credit for more than two check valves in series that are inspected and maintained. There are widely differing practices to estimate reverse flow with an inspected and maintained check valve that has severe leakage. It is up to the user to determine how to estimate.

Two practices are presented below. The reverse flow is calculated using the orifice area, the relief fluid properties, the maximum operating pressure on the side normally downstream of the check valve, and the allowable accumulation on the side normally upstream of the check valve.

The orifice area is calculated using the normal fluid properties, maximum operating pressure on the upstream side of the check valve, and the maximum operating pressure on the downstream side of the check valve.

To determine the reverse flow rate, this orifice is then rated using the relief fluid properties, the maximum operating pressure on the side normally downstream of the check valve, and the allowable accumulation on the side normally upstream of the check valve. The hydraulics profile should be based on the high-pressure side at maximum operating pressure and the low-pressure side at allowable accumulation.

The hydraulic calculations should take into account the effect of fluid phase change during the reverse flow when applicable e. Reciprocating compressors should be protected from rod packing failures in the distance piece by an adequately sized vent line or PRD. Options to size the PRD or vent line can include the following:. An alarm may be provided to indicate to operators that there is abnormally high packing leak off rate e. If overpressure protection is to be provided against internal explosions caused by ignition of vapor-air mixtures where the flame speed is subsonic i.

These devices respond in milliseconds. In contrast, relief valves react too slowly to protect the vessel against the extremely rapid pressure buildup caused by internal flame propagation.

The vent area required is a function of a number of factors including the following:. It should also be noted that the peak pressure reached during a vented explosion is usually higher, sometimes much higher, than the pressure at which the vent device activates. Design of explosion-relief systems should follow recognized guidelines such as those contained in NFPA 68 []. Simplified rules-of-thumb should not be used as these can lead to inadequate designs. If the operating conditions of the vessel to be protected are outside the range over which the design procedure applies, explosion vent designs should be based on specific test data, or an alternate means of explosion protection should be used.

Some alternate means of explosion protection are described in NFPA 69 [], including explosion containment, explosion suppression, oxidant-concentration reduction, and so forth. Explosion-relief systems, explosion containment, and explosion suppression should not be used for cases where detonation is considered a credible risk. In such cases, the explosion hazard should be mitigated by preventing the formation of mixtures that could detonate.

Explosion prevention measures, such as inert gas purging, in conjunction with suitable administrative controls can be considered in place of explosion-relief systems for equipment in which internal explosions are possible only as a result of air contamination during start-up or shutdown activities. The probability of hydraulic shock waves, known as water hammer, occurring in any liquid-filled system should be carefully evaluated.

Water hammer is a type of overpressure that cannot be controlled by typical PRVs, since the response time of the valves can be too slow. The oscillating pressure peaks, measured in milliseconds, can raise the normal operating pressure by many times. These pressure waves damage the pressure vessels and piping where proper safeguards have not been incorporated. Water hammer is frequently avoided by limiting the speed at which valves can be closed in long pipelines.

Where water hammer can occur, the use of pulsation dampeners, special bladder-type accumulators, or surge valves should be considered, contingent on proper analysis.

An oscillating peak-pressure surge, called steam hammer, can occur in piping that contains compressible fluids. The most common occurrence is generally initiated by rapid valve closure. This oscillating pressure surge occurs in milliseconds, with a possible pressure rise in the normal operating pressure by many times, resulting in vibration and violent movement of piping and possible rupture of equipment.

PRVs cannot effectively be used as a protective device because of their slow response time. Avoiding the use of quick-closing valves can prevent steam hammer. Isolation of a steam bubble by cold condensate can lead to the eventual rapid collapse of the bubble and catastrophic damage to steam pipework. Proper design and operation of the process system are essential in attempts to eliminate this possibility e. The hazard is particularly acute during turnaround and maintenance activities where dead-legs that trap a steam bubble can be inadvertently created.

PRDs cannot effectively be used as a protective device. The result can exceed the intended limits of the materials selected. Thus, where cryogenic fluids are being processed, a reduction in pressure could lower the temperature of the fluids to a level below the minimum allowable design temperature of the equipment, with the attendant risk of a low-temperature brittle failure.

For exothermic reactions e. The potential for a chemical reaction in conjunction with the other overpressure scenarios in 4. The design basis upset conditions are process specific but generally include one or more of the following:. Reaction rates are rarely known; therefore, bench-scale tests simulating the design basis upset condition are usually required.

There are a number of test apparatus available for this purpose. Typically, tempered systems are liquid-phase reactions in which a reactant or solvent is a major portion of the reactor contents.

Gassy systems can be either liquid-phase decompositions or vapor-phase reactions. Following characterization of the system, the appropriate vent-sizing formula can be selected. An excellent discussion of these procedures is contained in Grolmes et al. However, the reader should be cautioned that this is an area with rapidly changing technology and the most current technology should be used, if available.

If the bench-scale simulations indicate the potential for an explosion, the considerations in 4. It can also be prudent to consider housing the reactor in a specially constructed bay to handle potentially explosive reactions or to increase the equipment-design conditions to contain maximum expected temperature and pressure.

Where feasible, a PRD should be used to control overpressure. Where this is infeasible, other design strategies can be employed to control equipment overstressing. These strategies can include using safety systems such as automatic shutdown systems, inhibitor injection, quench, de-inventorying, alternative power supplies, and depressuring. When this approach is taken, the reliability of the protective system s should be addressed in a formal risk analysis.

This analysis is outside the scope of this standard. Other forms of reactions that generate heat dilution of strong acids should also be evaluated. Hydraulic expansion is the increase in liquid volume caused by an increase in temperature see Table 2. It can result from several causes, the most common of which are the following.

For other temperatures, Equation 4 can be used to estimate the cubical expansion coefficient. In certain installations, such as cooling circuits, the processing scheme, equipment arrangements and methods, and operation procedures make feasible the elimination of the hydraulic expansion relieving device, which is normally required on the cooler, fluid side of a shell-and-tube exchanger.

Typical of such conditions are multiple-shell units with at least one cold-fluid block valve of the locked-open design on each shell and a single-shell unit in a given service where the shell can reasonably be expected to remain in service, except on shutdown. In this instance, closing the cold-fluid block valves on the exchanger unit should be controlled by administrative procedures and possibly the addition of signs stipulating the proper venting and draining procedures when shutting down and blocking in.

Such cases are acceptable and do not compromise the safety of personnel or equipment, but the designer is cautioned to review each case carefully before deciding that a relieving device based on hydraulic expansion is not warranted because the corrected hydrotest pressure could be exceeded if the administrative procedures are not followed.

The required relieving rate is not easy to determine. Since every application is for a relieving liquid, the required relieving rate is small; specifying an oversized device is, therefore, reasonable. If there is reason to believe that this size is not adequate, the procedure in 4. If the liquid being relieved is expected to flash or form solids while it passes through the relieving device, the procedure in 4.

Proper selection of the set pressure for these relieving devices should include a study of the design rating of all items included in the blocked-in system. The thermal-relief pressure setting should never be above the maximum pressure permitted by the weakest component in the system being protected.

However, the PRD should be set high enough to open only under hydraulic expansion conditions. If thermal-relief valves discharge into a closed system, the effects of backpressure should be considered. Long pipelines can be blocked in at or below ambient temperature; the effect of solar radiation raises the temperature at a calculable rate. See Parry [] for additional information on thermal relief.

If the fluid properties vary significantly with temperature, the worst-case temperature should be used. Alternatively, more sophisticated calculation methods that include temperature-dependent fluid properties can be used to optimize the size of the relief device. For liquid-full systems, expansion rates for the sizing of relief devices that protect against thermal expansion of the trapped liquids can be approximated using Equation 1 in SI units or Equation 2 in USC units:.

NOTE This information is best obtained from the process design data; however, Table 2 shows typical values for hydrocarbon liquids and water at NOTE For heat exchangers, this can be taken as the maximum exchanger duty during operation. NOTE Compressibility of the liquid is usually ignored. This calculation method provides only short-term protection in some cases. If the blocked-in liquid has a vapor pressure higher than the relief design pressure, then the PRD should be capable of handling the vapor-generation rate.

If discovery and correction before liquid boiling is expected, then it is not necessary to account for vaporization in sizing the PRD. Where the system under consideration for thermal relief consists of piping only does not contain pressure vessels or heat exchangers , a PRD might not be required to protect piping from thermal expansion if any of the following apply:. In contrast, multicomponent mixtures with a wide boiling range can always have sufficient vapor present to preclude becoming completely liquid-full.

The liquid- volume change upon solar heating, heat tracing, heating to ambient temperature, or heat from another source should be estimated to determine if the volume of the vapor pocket is sufficient for liquid expansion.

The pressure rise due to simultaneous heating of the pipe and blocked-in liquid can be calculated from Equation 3 Karcher [97] and CCPS [44] :. For the thermal expansion scenario, no credit should be taken for reverse flow back through a check valve i. Alternatives are to drill a small [e.

If the above criteria cannot be met for a piping system, then the following factors should be evaluated for the fluid and the piping system, when determining if a thermal-relief valve is warranted to protect the system:.

Fire exposure can also cause overheating of the vessel walls resulting in a reduction in material strength. For the purpose of this standard, fires are characterized as open pool fires see 4. A pool fire typically results from an ignited liquid spill while a jet fire results from an ignited pressurized leak.

The heat flux from jet fires is very high and localized whereas the heat flux from pool fires is lower and not localized. Confined pool fires are those that occur inside a structure or are confined by embankments thereby causing higher heat fluxes than open pool fires in some cases. Fire heat intensities can vary dramatically depending on fuel, ventilation, release rate, and other factors.

Typical ranges of heat intensities are as follows. Annex A describes fire scenarios in detail and provides guidance in modeling fires. This information may be useful for assessing fires that may have less intensity than that premised in 4.

Caution should be taken when using the Annex A method for sizing PRDs because it may underestimate the fire heat input. For the purposes of PRD sizing for equipment within the scope of this standard, the design fire scenario has been and continues to be an open pool fire. The recommended method was empirically derived to size PRDs for open pool fires. The method is supported by full-scale test data see A. It is important to apply the appropriate standard when sizing for fire relief because there are differences in assumptions for the fire pool fire intensity, exposed area, and other factors specified in those standards.

API is limited to aboveground liquid- petroleum or petroleum-products storage tanks and aboveground and underground refrigerated storage tanks designed for operation at gauge pressures from vacuum through An open pool fire can affect multiple vessels simultaneously. If the open pool fire involves other types of fuels e.

Relieving temperatures are often above the design temperature of the equipment being protected. If the elevated temperature is likely to cause vessel rupture, additional protective measures should be considered see 4. To determine vapor generation, it is necessary to recognize only that portion of the vessel that is wetted by its internal liquid and is equal to or less than 7.

NOTE Hydrocarbon fires can exceed 7. Various classes of vessels are operated only partially full. Table 4 gives recommended portions of liquid inventory for use in calculations. Wetted surfaces higher than 7. Also, vessel heads protected by support skirts with limited ventilation are normally not included when determining wetted area. The user shall specify whether to include the wetted surface area of connected piping in the wetted-area calculation.

The wetted area for spheres includes all area up to the maximum diameter. The criterion is supported by previous incidents and tests that have shown that pool fire flames can follow the underside profile of spheres resulting in the entire bottom hemisphere being exposed to a high fire heat load. Unwetted wall vessels are those that have no liquid in contact with the internal vessel walls e.

These include vessels that contain separate liquid and vapor phases under normal conditions but become single phase above the critical at relieving conditions.

Vessels can be designed to have internal insulation e. If, however, a vessel can become insulated by the deposition of coke or other materials, the vessel wall shall still be considered wetted for fire-relief sizing without credit for any insulating effects but additional protection should be considered see 4. A characteristic of a vessel with an unwetted internal wall is that heat flow from the wall to the contained fluid is low as a result of the heat transfer resistance of the contained fluid or any internal insulating material.

Heat input from a fire to the bare outside surface of an unwetted or internally insulated vessel can, in time, be sufficient to heat the vessel wall to a temperature high enough to rupture the vessel. Figure 1 and Figure 2 indicate how quickly an unwetted bare vessel wall can be heated to rupture conditions. Figure 1 illustrates the rise in temperature that occurs with time in the unwetted plates of various thicknesses exposed to open fire. For example, an unwetted steel plate 25 mm 1 in.

The figure indicates that at a stress of MPa 20, psi , an unwetted steel vessel ruptures in about 0. A source for time-dependent rupture stress for different metals is ASTM Data Series DS 11S1 [29], which contains stress rupture and other elevated temperature property data for wrought carbon steel. It is typically assumed that the vessel is isolated during a fire in order to simplify the analysis, although a more detailed analysis can be warranted in certain cases.

Crediting for flow paths that remain open during an overpressure event is generally an acceptable practice. There can also be actuated valves that fail in the closed condition when exposed to a fire.

It can be difficult to establish with a degree of certainty whether a particular line will indeed remain open under all fire conditions.

Further, consideration should be given to the potential that the fire-relief flow in the flow path will overpressure other equipment. Hence, it can be necessary to add the fire-relief load elsewhere. Ultimately, the user shall decide whether a scenario is credible or not. Either the vapor thermal-expansion-relief load or the boiling-liquid vaporization-relief load, but not both, should be used. It is a practice that has been used for many years.

There are no known experimental studies where separate contributions of vapor thermal expansion versus boiling-liquid vaporization have been determined. When sizing the PRD for fire exposure, the contribution of vaporizing liquid compared with vapor expansion is generally governing unless, for example, the wetted surface has external insulation in accordance with 4. Key X time after start of the fire, expressed in minutes Y plate temperature, averaged over 2. There is an existing finger-type slug catcher in the inlet section of this plant that receives a three-phase gas stream from a inch pipeline.

I have the following question regarding of depressurization system for this part of the plant. Question: Is there any requirement to depressurize this system in case of fire detection?

If yes, please let me know if the criteria are based on API , Section 3 19 or are there other criteria for this case? API does not provide depressurization guidance for specific types of equipment or vessels.

It is up to the user to define what equipment is depressured. The statement where fire is controlling is intended to separate those applications where there are no reactive hazards. If there is a reactive hazard that can cause loss of containment due to over-temperature, then emergency depressuring valves may be appropriate for equipment designed for any range of pressures or services. Consequently, the plate thickness is often less than one inch.

As stated in 3. This implies that depressuring to psig is not a requirement for the higher pressure applications. There are also the main header and unit headers and sub-headers going backwards from the flare into towards the protected equipment.

A lateral is defined as the section of pipe from single source relief device s outlet flange s downstream to a header connection where relief devices from other sources are tied-in. In other words, the relief flow in a lateral will always be from a single source. In contrast, the relief flow in a header can be from either a single or multiple sources simultaneously. Question1: Is the maximum load calculation based on the maximum operating pressure or on the design pressure?

Question 2: " maximum pressure" reported in Sect. Typically, this would be the maximum normal operating pressure. A higher pressure e.

API does not have specific guidelines for measures to prevent potential plugging at the outlet of a relief valve in wet liquid propane service. Good engineering practice should include a design which minimizes the potential relief of wet liquid propane, through limiting the services where wet propane is present in a liquid filled system subject to pressure relief, overfilling protection for partially filled equipment, and design of liquid filled system so that the relief valve setting is above the highest hydraulic pressure possible during operation.

The rated capacity of the pressure relief valve not the actual capacity should be used to size the tailpipe and the laterals in the discharge line of the pressure relief device. Common header systems should use the cumulative required capacities of all devices that may reasonably be expected to discharge simultaneously in a single overpressure event see 5. For example, if a flare knockout drum is sized to remove liquid particles between and microns, this vessel would be too small if the nozzles shear the liquids to particle sizes of about 20 microns.

Whether the liquid droplets are either smaller than microns to start with or are sheared through the knock out drum nozzle to sizes smaller than microns, they will not adversely affect flare performance or safety if the mass flux and thermal radiation values are within the flare design range since the flare can handle small liquid droplets. There is a potential for increased thermal radiation fluxes and smoking potential but the effect should be small.

What are the consequences if the droplet sizes increase above the recommended value? Does this criteria apply to all types of flares? The recommended droplet size of to microns is based on experience with pipe flares. Droplets of smaller size would behave similar to combustion of gas. Droplets of larger size can result in incomplete combustion with excessive smoking, possible burning rain, and even flame-out.

Because some types of flares can accommodate larger droplets of combustible liquids, the vendor should always be consulted regarding the adequacy of a specific flare in burning liquids. The noise level sound power level expressed by Equation 58 is for either the noise due to flow across the pressure relief valve or the noise generated by flow across the discharge pipe outlet wherever the final discharge point is to atmosphere.

Can I extrapolate Figure 23? The noise calculations presented in Figure 23 are for noise generated during critical flow, and is not intended for use when the flow is not choked, nor should it be extrapolated beyond the values presented.

As the pressure ratio is defined as the absolute static pressure upstream from the restriction e. Yes, provided all of the criteria in B. One of the four criteria to be satisfied is that no means can exist for blocking any of the equipment components being protected from the installation of the single pressure relief device unless closure of these valves is positively controlled as described in API Recommended Practice , Part II, Section 2.

Question: Can we provide locked open or car-sealed open valves in the interconnecting piping between the equipment components protected by a single relief device? Others are interpreting that B.

Appendix B offers an example of a single relief valve protecting several equipment components. Section B. It does not unconditionally provide guidance on the relief device set point. RP , Section B. The relief valve is usually set at design pressure but consideration should be given to proper blowdown. No, API does not have any minimum volume requirements as to when to exclude an overpressure scenario. If the fire scenario is considered for a shell and tube heat exchanger full of liquid should we size the safety valve based on single or two phase equations?

As stated in API Std. We dont know if a heat exchanger shell with some baffles and tubes inside could be interpreted as a narrow passage according to API paragraph above. It is up to the user to determine whether the internals within the shell-and-tube heat exchanger would result in two phase relief in a fire. References cited in Section 5. Now when applying this rule we discovered a significant difference in the result depending on the selection of the units, either SI or USC.

The root cause of the difference appears to be in the constants C1 and C1, which have a different dimension when the exponent applied to the " total wetted surface" is changed from 0. Applying the same constants C1 and C2 would result in a significant difference in the calculated Total heat absorption depending on the selected units.

You have noted correctly that the equations were originally derived in USC units. When applying Equations 6 and 7 in section 5. When applying these equations in USC units, the correct values of C1 and C2 are and , respectively. An Addendum was issued noting this correction along with several unrelated additions to the J anuary 5th edition. Sponsored Links -. Join Date Jun Posts My threads; krishnagopi :. Originally Posted by pmx. Yes, the has been out there for quite some time, but now it is superseded.

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