Api rp 521 1997 scan (american petroleum institute)

4 E N E R A L

Scope

This recommended practice focuses on pressure-relieving and vapor depressuring systems, offering guidance for selecting the most suitable system based on specific risks and installation circumstances It aims to enhance the design foundation established in API Recommended Practice 520, Part 1.

This practice offers essential guidelines for analyzing the main causes of overpressure, calculating specific relieving rates, and selecting as well as designing disposal systems, which encompass components like vessels, flares, and vent stacks.

Piping information pertinent to pressure-relieving systems is presented in 5.4.1, but the actual piping should be designed in accordance with ASME B3 1.3 or other applicable codes

Health risks may be associated with the operation of pressure-relieving equipment The discussion of specific risks is outside the scope of this document.

Referenced Publications

The most recent editions of the following standards, codes, and specifications are cited in this recommended practice

Additional references are listed at the end of Sections 3, 4, and 5 and in the Bibliography, Section 6

Sizing, Selection, and Installation of Pres- sure-Relieving Devices in Refineries

Flanged Steel Safety-Relief Valves Seat Tightness of Pressure Relief Valves Venting Atmospheric and Low-Pressure Stor- age Tanks: Nonrefrigerated and Refrigerated

Protection Against Ignitions Arising Out of Static, Lightning, and Stray Currents

Purging Principles and Practice (Catalog Number XK0775)

Boiler and Pressure Vessel Code, Section I, “Power Boil- ers,” and Section VIII, “Pressure Vessels,” Division 1

B3 1.3 Chemical Plant and Petroleum Rejnery Piping

30 Flammable and Combustible Liquid Code

325M Fire-Hazard Properties of Flammable Liq- uids, Gases, and Volatile Solids, Volume I

Definition of Terms

This recommended practice defines terms related to pressure-relieving systems, specifically in sections 1.3.1 to 1.3.37 The definitions are primarily sourced from API Recommended Practice 520, Part I, and ASME PTC.

1.3.1 accumulation: The pressure increase over the maximum allowable working pressure of a vessel during discharge through the pressure relief device, expressed in pressure units or as a percent Maximum allowable accumula- tions are established by applicable codes for operating and fire contingencies

1.3.2 atmospheric discharge: The release of vapors and gases from pressure-relieving and depressuring devices to the atmosphere

1.3.3 back pressure: The pressure that exists at the outlet of a pressure relief device as a result of the pressure in the discharge system Back pressure can be either constant or variable Back pressure is the sum of the superimposed and built-up back pressures

Ignition Risk of Hydrocarbon Vapors by Hot 1.3.4 balanced pressure relief Valve: A spring-loaded

Sulfaces in Open Air pressure relief valve that incorporates a means for minimizing the effect of back pressure on the performance characteristics

Fireproojing Practices in Petroleum and Pet- rochemical Processing Plants (out of print)

’American Gas Association, 1515 Wilson Boulevard, Arlington, Virginia

Design and Construction of LP-Gas Installa- 22209 tions at Marine and Pipeline Terminals, Nut- york, New York ’American Society of Mechanical Engineers, 345 10017 East 47th Street, New

Ural Gas Processing Plants, Petrochemical 3National Fire Protection Association, 1 Batteryrnarch Park, Quincy, Mas-

Plants, and Tank Farms sachusetts 02269

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2 API RECOMMENDED PRACTICE 521 of the pressure relief valve (see Recommended Practice 520,

1.3.5 blowdown: The difference between the set pressure and the closing pressure of a pressure relief valve, expressed as a percentage of the set pressure or in pressure units

1.3.6 built-up back pressure: The increase in pressure in the discharge header that develops as a result of flow after the pressure relief device or devices open

1.3.7 burst pressure: The inlet static pressure at which a rupture disk device functions

1.3.8 closed-bonnet pressure relief valve: A pressure relief valve whose spring is totally encased in a metal housing This housing protects the spring from corrosive agents in the environment and is a means of collecting leakage around the stem or disk guide The bonnet may or may not be sealed against pressure leakage from the bonnet to the surrounding atmosphere, depending on the type of cap or lift- ing-lever assembly employed or the specific handling of bonnet venting

1.3.9 closed disposal system: A disposal system capable of containing pressures that are different from atmospheric pressure

1.3.10 cold differential test pressure: The pressure at which the pressure relief valve is adjusted to open on the test stand The cold differential test pressure includes corrections for the service conditions of back pressure or temperature or both

1.3.1 1 conventional pressure relief valve: A spring- loaded pressure relief valve whose performance characteristics are directly affected by changes in the back pressure on the valve (see Recommended Practice 520, Part I)

1.3.12 design pressure of a vessel: At least the most severe condition of coincident temperature and gauge pressure expected during operation It may be used in place of the maximum allowable working pressure in all cases where the maximum allowable working pressure has not been established The design pressure is the pressure used in the design of a vessel to determine the minimum permissible thickness or other physical characteristics of the different parts of the vessel (see also maximum allowable working pressure)

Flare systems are essential for the safe disposal of waste gases through combustion Elevated flares conduct combustion at the top of a pipe or stack, housing the burner and igniter, while ground flares operate at or near ground level In contrast, burn pits are specifically designed to manage liquid waste.

1.3.14 huddling chamber: An annular pressure chamber in a pressure relief valve located beyond the seat for the purpose of generating a rapid opening

1.3.15 lift: The actual travel of the disk away from the closed position when a valve is relieving

The sum of the maximum allowable working pressure and the maximum allowable accumulation

1.3.17 maximum allowable working pressure: The maximum gauge pressure permissible at the top of a com- pleted vessel in its operating position for a designated temperature The pressure is based on calculations for each element in a vessel using nominal thicknesses, exclusive of additional metal thicknesses allowed for corrosion and loadings other than pressure The maximum allowable working pressure is the basis for the pressure setting of the pressure relief devices that protect the vessel

The open-bonnet pressure relief valve features a spring that is directly exposed to the atmosphere via the bonnet or yoke This design allows for ambient air to circulate freely around the spring, providing cooling and potentially protecting it from contact with any vapors or gases released by the valve.

1.3.19 open disposal system: A disposal system that discharges directly from the relieving device to the atmosphere with no containment other than a short tail pipe

1.3.20 operating pressure: The pressure to which the vessel is usually subjected in service A pressure vessel is normally designed for a maximum allowable working pressure that will provide a suitable margin above the operating pressure in order to prevent any undesirable operation of the relieving device

1.3.21 overpressure: The pressure increase over the set pressure of the relieving device, expressed in pressure units or as a percent It is the same as accumulation when the relieving device is set at the maximum allowable working pressure of the vessel, assuming no inlet pipe loss to the relieving device

When the set pressure of the primary pressure relief valve is lower than the vessel's maximum allowable working pressure, the overpressure can exceed 10 percent of the valve's set pressure.

1.3.22 pilot-operated pressure relief valve: A pressure relief valve in which the main valve is combined with and controlled by an auxiliary pressure relief valve

1.3.23 pressure relief valve: A generic term applied to relief valves, safety valves, and safety relief valves A pressure relief valve is designed to automatically reclose and prevent the flow of fluid

GUIDE FOR PRESSURE-RELIEVING AND DEPRESSURING SYSTEMS 3

1.3.24 pressure-relieving system: An arrangement of a pressure-relieving device, piping, and a means of disposal intended for the safe relief, conveyance, and disposal of fluids in a vapor, liquid, or gaseous phase A relieving system may consist of only one pressure relief valve or rupture disk, either with or without discharge pipe, on a single vessel or line A more complex system may involve many pressure-relieving devices manifolded into common headers to terminal disposal equipment

1.3.25 quenching: The cooling of a fluid by mixing it with another fluid of a lower temperature

1.3.26 rated relieving capacity: That portion of the measured relieving capacity permitted by the applicable code or regulation to be used as a basis for the application of a pressure relief device

OF OVERPRESSURE

General

This section explores the main causes of overpressure in refinery equipment and provides design recommendations to mitigate these effects Overpressure occurs when there is an imbalance or disruption in the normal flow of material and energy, leading to accumulation in certain areas of the system Consequently, analyzing the causes and magnitudes of overpressure requires a detailed and complex examination of material and energy balances within the process system.

The application of the principles in this section will vary for each processing system, and while major circumstances have been addressed, users should not view the described conditions as the sole causes of overpressure This recommended practice offers only suggestive guidance on overpressure treatment It is essential to consider any situation that may pose a hazard under the current system conditions during the design process Pressure-relieving devices are crucial for preventing any process system or its components from experiencing pressures that surpass the maximum allowable accumulated pressure.

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Overpressure Criteria

Overpressure causes, such as external fires, are deemed unrelated if there are no process, mechanical, or electrical connections between them, or if the time interval between potential occurrences is long enough to classify them as separate Additionally, the simultaneous occurrence of multiple conditions leading to overpressure will not be assumed if the causes are considered unrelated.

Operator error is considered a potential source of overpressure

The practices evaluated in this section should be used in conjunction with sound engineering judgment and with full consideration of federal, state, and local rules and regulations

Certain relief scenarios necessitate the installation of high-integrity protective instrument systems to mitigate risks of overpressure and over-temperature When implementing this solution, the protective instrument system must demonstrate reliability equivalent to that of a pressure-relief device system and should only be considered when pressure relief devices are not feasible.

Fail-safe devices and automatic start-up equipment should not be seen as substitutes for pressure-relieving devices in protecting individual process equipment In designing components of a relieving system, such as the blowdown header and flare, it is reasonable to assume a favorable response from a certain percentage of instrument systems This percentage is typically determined by considering factors like redundancy, maintenance schedules, and overall instrument reliability.

Potentials for Overpressure

Pressure vessels, heat exchangers, operating equipment, and piping are engineered to withstand system pressure, taking into account the normal operating pressure at specific temperatures, potential mechanical loadings, and the pressure differential related to pressure-relieving devices Designers must establish the minimum relief necessary to ensure that pressure in any equipment does not surpass the maximum allowable accumulated pressure The primary causes of overpressure, as outlined in sections 2.3.2 to 2.3.16, provide guidance for widely accepted safety practices.

Inadvertently closing a block valve on a pressure vessel's outlet while the plant is operational can lead to overpressure, exceeding the maximum allowable working pressure To mitigate this risk, a pressure relief device is essential unless administrative controls, like car seals or locks, are implemented to manage valve closure It is crucial to treat every control valve as potentially subject to inadvertent operation Additionally, omitting block valves between vessels in a series can streamline pressure-relieving requirements.

In system capacity design, it is assumed that control valves, which are normally open and operational at the time of failure, will continue to function at their normal positions if they are not impacted by the primary cause of the failure For more details, refer to section 3.10.4.

The unintentional opening of a valve connected to a high-pressure source, like steam or process fluids, poses significant risks To mitigate these dangers, it is essential to ensure adequate pressure-relieving capacity or implement measures to securely lock or seal the valve in a closed position.

The failure of a check valve to close can lead to significant issues, particularly when a fluid is pumped into a system containing gas or vapor at higher pressures than the equipment's design rating If flow ceases and the check valve fails in the discharge line, it can cause a reversal of liquid flow, potentially leading to dangerous overpressure conditions While a single check valve is often deemed sufficient, it may not be adequate if there's a risk of backflow from high-pressure fluids that could exceed the equipment's test pressure In such scenarios, implementing a secondary device, such as a nonreturn valve or a power-assisted check valve, is advisable to mitigate the risk of flow reversal Additionally, sizing pressure-relieving facilities on the suction side for peak flow after a check valve failure is generally discouraged, as reverse flow through rotating machinery can generate centrifugal forces that may damage mechanical equipment.

Evaluating the potential consequences of losing any utility service, whether on a plantwide or local scale, is crucial Table 1 provides a list of typical utility services that may fail and outlines the equipment that could be impacted, potentially leading to over-pressure situations.

GUIDE FOR PRESSURE-RELIEVING AN0 DEPRESSURING SYSTEMS 5

Table l-Possible Utility Failures and Equipment

Electric Pumps for circulating cooling water, boiler feed, quench, or reflux combustion air

Fans for air-cooled exchangers, cooling towers, or Compressors for process vapor, instrument air,

Instrumentation Motor-operated valves Condensers for process or utility service Coolers for process fluids, lubricating oil, or seal

Jackets on rotating or reciprocating equipment Transmitters and controllers

Process-regulating valves Alarm and shutdown systems Turbine drivers for pumps, compressors, blowers,

Reboilers Reciprocating pumps Equipment that uses direct steam injection Eductors vacuum, or refrigeration oil combustion air fans, or electric generators

Fuel (oil, gas, etc.) Boilers

Reheaters (reboilers) Engine drivers for pumps or electric generators Compressors

Catalytic reactors Purge for instruments and equipment

An evaluation of the impact of overpressure due to the loss of a utility service must consider the potential chain of events and the associated reaction time In cases where equipment fails but operates alongside other equipment with different energy sources, credit may be taken for the functioning equipment that maintains service For instance, in a cooling-water circulating system with two parallel pumps driven by unrelated energy sources, if one source fails, partial credit can be attributed to the operational pump The excess vapor generated from the energy failure is then determined by the amount of cooling water lost Conversely, in a scenario with two cooling-water pumps where one is in standby mode with a separate energy source, no credit is given for the standby pump, as it is not deemed fully reliable.

A thorough analysis indicates that full or partial protective credit can be applied to parallel instrument air compressors and electric generators that operate normally and are powered by two independent energy sources However, the manual activation of auxiliary systems is contingent on operator actions and timing, necessitating careful evaluation before relying on it as a safeguard against overpressure.

The failure of electrical or mechanical equipment that provides cooling or condensation in process streams can cause overpressure in process vessels

Air-cooled heat exchangers and cooling towers may occasionally fail due to power loss or mechanical issues However, in systems where louvers can operate independently, cooling effects can still be achieved through convection and radiation in still air under ambient conditions.

2.3.9 LOSS OF HEAT IN SERIES FRACTIONATION SYSTEMS

In series fractionation, where the bottoms from one column feed into the next, a loss of heat input can lead to overpressure in the subsequent column This heat loss causes some light ends to mix with the bottoms and be transferred as feed to the next column Consequently, the overhead load of the second column may include both its normal vapor load and the additional light ends from the first column If the second column lacks sufficient condensing capacity for this increased vapor load, it may experience excessive pressure.

2.3.10 LOSS OF INSTRUMENT AIR OR ELECTRIC

The automation of instruments in process units necessitates reliable and continuous air or electric power sources for effective operation In cases where a single instrument air compressor is used, a sufficiently large air receiver can be adequate, provided it is supported by an emergency pressure-reducing station connected to the plant's air system.

Key electronic or electrical instruments should be intercon- nected with an emergency electric source of the proper AC or

When designing a plant, it is crucial to evaluate the fail-safe condition of each control valve, which determines its action—whether spring open, spring closed, or fixed position—during a loss of operating air or electric power Properly establishing the fail-safe characteristics of control valves minimizes the risk of overpressure, ensuring safety and reliability in operations.

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Inadequate relief protection can occur when failures in an instrument system lead to a control valve moving contrary to its intended failure position, as outlined in API Recommended Practice 521.

The loss of reflux as a result of pump or instrument failure can cause overpressure in a column because of condenser flooding or loss of coolant in the fractionating process

Reboilers are engineered to operate with a specific heat input, but when they are newly installed or recently serviced, they may experience increased heat input beyond their normal design capacity If temperature control fails, the resulting vapor generation can surpass the system's capacity to condense or manage pressure buildup, potentially leading to the presence of noncondensable gases due to overheating.

OF INDIVIDUAL RELIEVING RATES

Principal Sources of Overpressure

a plant or its personnel be compromised

Table 2 outlines common scenarios necessitating overpressure protection, serving as a guide rather than a comprehensive list of maximum relief capacities It emphasizes the importance of applying good engineering judgment instead of strictly adhering to the proposals The subsequent sections offer a more detailed analysis of the results, focusing on economic and operational considerations.

Table 2-Bases for Relief Capacities Under Selected Conditions ltem No Condition Pressure Relief Device (Liquid Relief)" Pressure Relief Device (Vapor Relief)"

Cooling water failure to condenser Top-tower reflux failure

Lean oil failure to absorber Accumulation of noncondensables

Entrance of highly volatile material Water into hot oil

Light hydrocarbons into hot oil

Overfilling storage or surge vessel Failurc of automatic controls Abnormal heat or vapor input Split exchanger tube lnternal explosions Chemical reaction

Cold fluid shut in Lines outside process area shut in Exterior fire

Power failure (steam, electric, or other) Fractionators

Air-cooled exchangers Surge vessels

Maximum liquid pump-in rate

Total incoming steam and vapor plus that generated thereln at

Total vapor to condenser at relieving conditions Total incoming steam and vapor plus that generated therein at relieving conditions less vapor condensed by sidestream reflux relieving conditions

Difference between vapor entering and leavmg section at relieving conditions

None, normally Same effect in towers as found for Item 2; in other vessels, same effect as found for Item 1

In tower systems, predictability is often limited For heat exchangers, it is advisable to allocate an area that is twice the internal cross-sectional area of a single tube This additional space accounts for the vapor generated when a volatile fluid enters due to a tube rupture.

Must be analyzed on a case-by-case basis Estimated maximum vapor generation including non-con-

Steam or vapor entering from twice the cross-sectional arca of one tube; also same effects found in ltem 7 for exchangers densables from overheating

Not controlled by conventional relief devices but by.avoid- ance of circumstances

Estimated vapor generation from both normal and uncon- trolled conditions

Estimated by the method given in 3 I5

Study the installation to determine the effect of power failure; size the relief valve for the worst condition that can occur

All pumps could be down, with the result that reflux and cooling water would fail

Consider failure of agitation or stirring, quench or retarding stream: size the valves for vapor generation from a runaway reaction

Fans would fail; size valves for the difference between normal and emergency duty

"Consideration may be given to the reduction of the relief rate as the result of the relieving pressure being above operating pressure

Sources of Overpressure

The relief requirements are determined by the net energy input, which can be categorized into two primary forms: (a) heat input, resulting from indirect pressure through vaporization or thermal expansion, and (b) direct pressure input from higher pressure sources.

Overpressure may result from one or both of these sources

The peak individual relieving rate is the highest rate required to safeguard equipment from overpressure caused by any single factor The likelihood of two unrelated failures happening at the same time is very low and typically does not need to be taken into account.

Effects of Pressure, Temperature, and Composition

Pressure and temperature are crucial factors in determining individual relieving rates, as they influence the volumetric and compositional behavior of liquids and vapors When heat is applied to a liquid, vapor is produced, and the generation rate of this vapor varies with equilibrium conditions due to increased pressure in confined spaces and the heat content of incoming and outgoing streams Often, a liquid volume consists of a mixture of components with varying boiling points Under pressure-relieving conditions, heat applied to fluids that do not reach their critical temperature results in vapor that is rich in low-boiling components, with progressively heavier components being generated as heat input continues.

Finally, if the heat input is sufficient, the heaviest components are vaporized

During pressure relief, it is essential to analyze the variations in vapor rates and molecular weights over different time intervals This investigation helps identify the peak relieving rate and the composition of the vapor, as outlined in API Recommended Practice 520, Part.

I) The composition of inflowing streams may also be affected by variations in time intervals and, therefore, requires study

When relieving pressure in a system, it may surpass the critical or pseudocritical pressure of its components In these situations, it is essential to utilize compressibility correlations to accurately calculate the relationships between density, temperature, and enthalpy of the fluid If the overpressure arises from an influx of excess material, the surplus mass must be released at a temperature that balances the incoming enthalpy with the outgoing enthalpy.

In a closed system with no inflow or outflow, overpressure caused by excess heat input requires relief based on the difference between initial and remaining contents over time The total extraneous enthalpy input equals the overall gain in enthalpy of the original contents, regardless of whether they stay in the container or are vented By analyzing the cumulative vent quantity over time, one can identify the maximum instantaneous relieving rate, which typically occurs close to the critical temperature.

In situations where physical properties of the fluid are unknown, relying on the ideal gas assumption can lead to overly conservative estimates, resulting in the oversizing of the safety relief valve as indicated by Equation 5 (refer to section 3.15.2.1.2).

Effect of Operator Response

When determining maximum relieving conditions, it is crucial to consider the operators responsible for the response and the potential consequences of incorrect actions Typically, the accepted response time ranges from 10 to 30 minutes, influenced by the complexity of the plant The effectiveness of this response is significantly affected by the process dynamics.

Closed Outlets

To ensure the safety of a vessel or system from overpressure when all outlets are blocked, the relief device must have a capacity equal to or greater than the pressure sources If some outlets remain unblocked, their capacity can also be taken into account Key sources of overpressure include pumps, compressors, high-pressure supply headers, stripped gases from rich absorbents, and process heat In heat exchangers, a closed outlet can lead to thermal expansion or vapor generation.

The amount of material to be relieved must be calculated based on the set pressure plus overpressure, rather than normal operating conditions This approach often significantly reduces the required valve capacity Additionally, it is essential to account for the friction drop in the connecting line between the overpressure source and the protected system when determining the capacity requirements.

Cooling or Reflux Failure

The relieving rate in a distillation system is established through a heat and material balance at the relieving pressure, and calculations may vary depending on whether reflux is included Typically, the impact of residual coolant after a cooling stream failure is not accounted for, as it is time-limited and influenced by the piping's physical configuration However, in cases where the process piping system is significantly large and exposed, heat loss to the surroundings may be taken into consideration.

Because of the difficulty in calculating detailed heat and material balances, the simplified bases described in 3.6.2 through 3.6.9 have generally been accepted for determining relieving rates

The relief requirement refers to the total incoming vapor rate to the condenser, adjusted for the new vapor composition at the set pressure plus overpressure, along with the prevailing heat input during relief The surge capacity of the overhead accumulator at the normal liquid level is typically restricted to under 10 minutes If a cooling failure lasts longer than this duration, reflux is compromised, leading to significant changes in the overhead composition, temperature, and vapor rate.

The relief requirement is defined as the difference between the incoming and outgoing vapor rates under relieving conditions To accurately calculate the incoming vapor rate, the same basis outlined in section 3.6.2 must be used If there are any changes in the composition or rate of the reflux, it is essential to reassess the incoming vapor rate to the condenser based on the new conditions.

Due to natural convection effects, a partial condensing capacity of 20% to 30% of normal duty is typically credited unless significant differences are identified under relieving conditions Consequently, the relief valve capacity is calculated based on the remaining 70% to 80%, depending on the specific service requirements The actual duty available from natural convection largely depends on the design of the air-cooled heat exchanger, with some designs potentially allowing for greater credits if supported by engineering analysis Additionally, the cooling capabilities may be reduced if variable pitch fans are employed and the pitch mechanism fails.

Louver closure on air-cooled condensers signifies a complete failure of the coolant, leading to capacity issues as outlined in sections 3.6.2 and 3.6.3 This closure can occur due to failures in automatic control systems, mechanical linkages, or destructive vibrations affecting manually positioned louvers.

Failure of the reflux, often due to pump shutdown or valve closure, can lead to condenser flooding, resulting in a complete loss of coolant as outlined in sections 3.6.2 and 3.6.3 This loss may alter vapor properties, impacting system capacity While a valve designed for total coolant failure is typically sufficient, each situation should be assessed based on the specific components and system in use.

The relief requirement refers to the vaporization rate resulting from a heat amount equivalent to that removed in the pump-around circuit This rate is associated with the latent heat of vaporization, which corresponds to the latent heat under the specific relieving conditions of temperature and pressure at the relief point.

3.6.8 OVERHEAD CIRCUIT PLUS PUMP-AROUND

An overhead circuit combined with a pump-around system is designed to prevent simultaneous failures of both the pump-around and the overhead condenser However, it is still possible for one to partially fail while the other completely fails The necessary relieving capacity is addressed in sections 3.6.6 and 3.6.7.

In condenser flooding scenarios or when vapor properties change due to composition variations, principles akin to those outlined in sections 3.6.6 and 3.6.7 are applicable It is essential that the relieving capacity is sufficient to manage the vaporization rate generated by the typical heat removal from the system.

Absorbent Flow Failure

In lean-oil absorption systems for hydrocarbons, a failure typically does not necessitate a relief requirement However, in acid gas removal units where over 25% of the inlet vapor is absorbed, the loss of absorbent can lead to pressure increases that exceed relief pressure, as the downstream system may not accommodate the heightened flow The situation becomes more complex in synthesis-gas carbon dioxide removal units, particularly when the downstream gas is directed to a methanator An influx of carbon dioxide beyond the design capacity, which can occur during partial absorbent failure, results in a rapid temperature increase that often triggers the closure of the methanator feed shutoff valve and opens a vent to the atmosphere If this vent fails to operate, there is a risk of overpressure Therefore, each case must be thoroughly analyzed, considering the specific process and instrumentation characteristics, as well as the impact on downstream units and the immediate piping and instrumentation following the absorber.

Accumulation of Noncondensables

Noncondensables typically do not build up under normal conditions, as they are expelled along with process streams However, specific piping configurations can lead to the accumulation of noncondensables, potentially blocking the condenser and resulting in a complete loss of coolant.

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Entrance of Volatile Material Into the System

The introduction of water into hot oil poses a risk of overpressure, yet there are no widely accepted methods for determining the necessary relief requirements However, if the amount of water and the heat available in the process stream are known, it is possible to calculate the relief valve size similarly to that of a steam valve.

The exact quantity of water in a system is often unknown, making it challenging to manage vapor expansion, which can reach a ratio of approximately 1:1,400 at atmospheric pressure The rapid generation of vapor raises concerns about the effectiveness of pressure-relieving valves, which are typically not included in designs for this scenario To mitigate risks, it is crucial to ensure proper design and operation of the process system Key precautions include eliminating water-collecting pockets, installing effective steam condensate traps, and implementing double blocks and bleeds on water connections to hot process lines.

3.9.2 LIGHT HYDROCARBONS INTO HOT OIL

The information in 3.9.1 applies to the entrance of light hydrocarbons into hot oil even though the ratio of liquid volume to vapor volume may be considerably less than 1: 1,400.

Failure of Process Stream Automatic Controls

Automatic control devices are utilized at the inlets or outlets of vessels or systems, either directly or indirectly actuated by process variables like pressure, flow, liquid level, or temperature In the event of a failure in the transmission signal or operating medium to a final control element, such as a valve operator, these devices are designed to default to either a fully open or fully closed position It is important to note that final control elements that fail while stationary should be considered as having failed either fully open or fully closed.

The impact of a process-measuring element failure in a transmitter or controller, without a simultaneous power failure to the final controlled element, must be assessed to understand its effects on the final controlled element Additionally, the operation of the manual bypass valve is addressed.

3.16 Possible failure of the control device while the manual bypass valve is fully or partially open deserves to be considered; however, this factor is not intended to cover the condition of an undersized control valve

When assessing relief considerations, designers must assume that the control valve and unit operation are properly sized and functioning near design specifications, unless they are aware of specific contrary conditions It is crucial for designers to remain vigilant about temporary start-up or upset situations, particularly when operators utilize the bypass valve These scenarios often lead to off-control conditions, increasing the likelihood of relief requirements compared to normal operations with all bypasses closed.

When assessing relieving requirements, it is essential to assume that automatic control valves not contributing to the relieving requirement will remain in their normal processing flow position This means that no credit should be given for any favorable instrument response The normal valve position reflects the expected state before any incident, considering the system's design capacity and turn down Credit for normal flow through control valves can be taken, adjusted for relieving conditions, as long as the downstream system can accommodate the increased flow Although controllers influenced by factors other than system pressure may attempt to fully open their valves, credit for these control valves should only be granted based on their operating position during normal flow, irrespective of their initial condition.

In systems with single or multiple inlet lines equipped with control devices, it is crucial to consider that one inlet valve may remain fully open despite control valve failures, which can occur due to instrument malfunction or operator error When multiple inlets are present, the other control devices are assumed to be in their normal operating positions The necessary relief capacity is determined by the difference between the maximum expected inlet flow and the normal outlet flow, taking into account relieving conditions and unit turndown, while assuming other valves are functioning normally If any outlet valves are closed or additional inlet valves are opened due to the same failure, the relief capacity must be recalculated based on the maximum expected inlet flow and the normal flow from the remaining open outlet valves All flow calculations should be performed under relieving conditions, and it is essential to consider the impact of a partially open manual bypass on the inlet control valves.

Other situations may arise where problems involved in evaluating relief requirements after the failure of an inlet control device are more complex and of special concern (for

When designing pressure-relieving and depressurizing systems, it is crucial to consider the implications of transferring liquid from a high-pressure vessel to a low-pressure system, particularly when the low-pressure outlet is closed The primary concern is the flashing effect, but designers must also account for potential vapor flow into the low-pressure system if there is a loss of liquid level in the high-pressure vessel If the incoming vapor volume is significant relative to the low-pressure system's capacity, or if the vapor source is unlimited, this can lead to rapid over-pressure conditions Consequently, relief devices in the low-pressure system may need to be appropriately sized to manage the full vapor flow from the liquid control valve.

In process systems with substantial pressure differences, when the vapor volume in high-pressure equipment is smaller than that in the low-pressure system, excess pressure can sometimes be absorbed without causing overpressure.

In the event of a liquid level loss, vapor flow into the low-pressure system is influenced by the interconnecting system, which typically includes wide-open valves and piping, and is governed by the differential pressure between the upstream operating pressure and the downstream relieving pressure This initial pressure drop can lead to critical flow conditions, resulting in vapor inflow rates that may significantly exceed normal levels However, this situation is temporary, as the upstream reservoir will eventually deplete unless makeup equals outflow It is essential to size relief facilities to accommodate peak flow rates If the low-pressure side contains a substantial vapor volume, it may be beneficial to account for the transfer of vapors from the high-pressure system, which can help raise downstream pressure to the relieving pressure, thereby reducing upstream pressure and flow requirements Additionally, allowances should be made for the normal vapor makeup to the high-pressure system, which helps maintain upstream pressure.

When determining relief load for outlet control valves, it is essential to evaluate both fully opened and fully closed positions, irrespective of the control valve's failure position, which may arise from instrument system failures or misoperations If inlet valves are inadvertently opened due to the same failure that causes the outlet valve to close, pressure-relieving devices become necessary to avert overpressure situations The required relief capacity is calculated as the difference between maximum inlet and outlet flows, with all flows assessed under relieving conditions Additionally, the potential impact of inadvertent closure of control devices by operator actions should also be taken into account.

In applications with single outlets equipped with control devices that fail in the closed position, it is essential to install pressure-relieving devices to prevent overpressure The necessary relief capacity must match the maximum anticipated inlet flow under relieving conditions, as specified in section 3.5.

In systems with multiple outlets and a control device that fails in the closed position for one outlet, the necessary relief capacity is determined by calculating the difference between the maximum expected inlet flow and the design flow, adjusted for relieving conditions and unit turn-down, through the remaining operational outlets, while assuming that other valves in the system function normally.

In systems with multiple outlets, where control devices may fail in the closed position due to a common failure, the necessary relief capacity must match the maximum anticipated inlet flow under relieving conditions.

Control devices may stay in their last set position, but their valve position at the time of failure is unpredictable Designers must account for the possibility that these devices could be either open or closed, ensuring that there is no reduction in relief capacity when utilizing such devices.

Control devices, such as diaphragm-operated control valves, must function effectively not only under normal operating conditions but also during upset scenarios, including when pressure-relieving devices are activated It is crucial to select valve designs and operators that can accurately position the valve plug according to control signals during these abnormal conditions Since the capacities of control valves differ under pressure-relieving conditions compared to normal conditions, it is essential to calculate their capacities based on the specific relieving temperature and pressure to determine the necessary relief capacities Additionally, in extreme situations, the state of the controlled fluid may change, such as transitioning from liquid to gas or vice versa This variation can significantly affect the wide-open capacity of a control valve, particularly if it was initially selected for liquid handling but is required to manage gas, raising concerns about potential high-pressure gas passing into systems designed only for vapor from normal liquid levels.

Internal Explosion (Excluding Detonation)

For effective overpressure protection against internal explosions from vapor-air mixtures, it is essential to utilize rupture discs or explosion vent panels instead of relief valves, as the latter respond too slowly to the rapid pressure increase caused by flame propagation The required vent area depends on several factors, including initial conditions such as pressure, temperature, and composition, the flame propagation characteristics of the specific vapors or gases, the vessel's volume, the activation pressure of the vent device, and the maximum pressure that can be safely tolerated during a vented explosion incident.

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 recog- nized guidelines such as those contained in NFPA 68 [l]

Using simplified rules-of-thumb can result in inadequate designs for explosion venting When the operating conditions of the vessel exceed the applicable design range, it is essential to base explosion vent designs on specific test data or consider alternative explosion protection methods.

Note: Numbers in brackets correspond to references listed in 3.21

Some alternate means of explosion protection are described in NFF'A 69 [2], including explosion containment, explosion suppression, oxidant concentration reduction, and so forth

Explosion relief systems, containment, and suppression are inadequate when detonation poses a credible risk Instead, it is essential to mitigate explosion hazards by preventing the creation of potentially detonable mixtures.

To prevent explosions, inert gas purging combined with appropriate administrative controls can serve as an alternative to explosion relief systems This approach is particularly relevant for equipment where internal explosions may occur due to air contamination during start-up or shutdown processes.

Chemical Reaction

The methodology for determining the appropriate size of an emergency vent system for chemical reactions was established by DIERS (Design Institute for Emergency Relief Sys- tems) [31, ~41, PI, ~61, [71

The DIERS methodology involves defining the design basis upset conditions for the reaction system, characterizing these systems through bench scale tests that simulate the upset conditions, and applying vent sizing formulas that account for two-phase gas-liquid vent flow.

The design basis upset conditions are process specific, but generally include one or more of the following: a External fire b Loss of mixing c Loss of cooling d Mischarge of reagents

Reaction rates are often unknown, necessitating bench scale tests that simulate design basis upset conditions Various test apparatuses are available for this purpose The data gathered from these tests allows for the characterization of the system as either tempered or gassy Tempered systems produce condensable products from unwanted reactions, with temperature rise moderated by liquid boiling at system pressure, typically involving liquid phase reactions where a reactant or solvent constitutes a significant portion of the reactor contents In contrast, gassy systems generate noncondensable products, and their temperature rise is not moderated by boiling liquid.

Pressure-relieving and depressurizing systems can involve either liquid-phase decompositions or vapor-phase reactions Hybrid systems are characterized by a temperature rise from unwanted reactions that can be moderated by liquid boiling at system pressure, while also potentially producing noncondensable gases.

After characterizing the system, the correct vent sizing formula can be chosen Grolmes et al [3] provide a comprehensive discussion on these procedures However, it is important to note that this field is evolving quickly, and utilizing the latest technology is advisable whenever possible.

If bench scale simulations suggest the risk of an explosion, it is essential to implement the guidelines outlined in section 3.12 Additionally, it may be wise to place the reactor in a specially designed bay to manage potentially explosive reactions or to enhance the equipment's design specifications to withstand the maximum anticipated temperature and pressure.

To effectively manage overpressure, it is advisable to utilize a pressure relief device whenever possible If this is not feasible, alternative design strategies should be implemented to prevent equipment overstressing These strategies may involve safety systems like automatic shutdowns, inhibitor injection, quenching, de-inventorying, alternative power supplies, and depressurizing It is crucial to conduct a formal risk analysis to evaluate the reliability of these protective systems.

This analysis is outside the scope of this document

Other forms of reactions that generate heat (dilution of strong acids) should also be evaluated.

Hydraulic Expansion

Hydraulic expansion refers to the increase in liquid volume due to rising temperatures This phenomenon can occur for several reasons, including when piping or vessels filled with cold liquid are heated by heat tracing, coils, ambient heat, or fire Additionally, it can happen when an exchanger is blocked on the cold side while flow continues on the hot side Another cause is when piping or vessels filled with liquid at near-ambient temperatures are exposed to direct solar radiation, leading to increased temperatures and subsequent expansion.

In specific setups like cooling circuits, it is possible to eliminate the hydraulic expansion-relieving device typically needed on the cooler fluid side of a shell-and-tube exchanger This is feasible due to the processing scheme, equipment arrangements, and operational procedures in place A common scenario for this condition includes multiple-shell units that feature at least one cold-fluid block valve.

Table 3-Typical Values of Cubical Expansion Coefficient for Hydrocarbon Liquids and Water at 60°F

Gravity of Liquid (OAPI) Value (per "F)

Water 0.0001 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 instancc, 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

Determining the capacity requirement for a relieving device can be challenging, as every application will involve relieving liquid It is often reasonable to specify an oversized device, with a common choice being a %-inch X 1-inch nominal pipe size (NPS % X NPS 1) relief valve If there are concerns about the adequacy of this size, the procedure outlined in section 3.14.3 should be followed Additionally, if the liquid is expected to flash or form solids during the relief process, it is advisable to refer to the procedure in section 3.20.1.

Selecting the appropriate set pressure for relief devices requires a thorough examination of the design ratings of all components within the blocked-in system The thermal relief pressure must not exceed the maximum pressure allowed by the weakest part of the system being safeguarded Additionally, the pressure-relieving device should be calibrated to activate only under hydraulic expansion conditions It is also essential to account for back pressure effects when thermal relief valves discharge into a closed system.

Two general applications for which thermal relieving devices larger than a %-inch x 1-inch nominal pipe size (NPS

In large diameter, uninsulated aboveground installations and liquid-full vessels or exchangers, a % x NPS 1) valve may be necessary Long pipelines can become blocked at or below ambient temperatures, and solar radiation can increase the temperature within these systems.

To determine the relieving capacity requirement, it is essential to know the total heat transfer rate and the thermal expansion coefficient of the fluid For further details on thermal relief, refer to Parry [8].

For liquid-full systems, the sizing of relief devices to safeguard against thermal expansion of trapped liquids can be estimated using a specific formula.

500GC Where: gpm = flow rate at the flowing temperature, in U S gal-

B = cubical expansion coefficient per degree Fahren- lons per minute heit for the liquid at the expected temperature

This information is best obtained from the process design data; however, Table 3 shows typical values for hydrocarbon liquids and water at 60°F

H = total heat transfer rate, in British thermal units per hour For heat exchangers, this can be taken as the maximum exchanger duty during operation

G = specific gravity referred to water = 1 OO at 60°F

Compressibility of the liquid is usually ignored

C = specific heat of the trapped fluid, in British thermal units per pound per degree Fahrenheit

This calculation method offers only temporary protection in certain situations If the vapor pressure of the trapped liquid exceeds the relief design pressure, the pressure relief device must be able to manage the rate of vapor generation However, if it is anticipated that any issues will be identified and resolved before the liquid begins to boil, vaporization does not need to be considered when sizing the pressure relief device.

External Fire

3.15.1.1 Effect of Fire on the Wetted Surface of a

The wetted surface area of a vessel's internal liquid is crucial for vapor generation when exposed to fire, specifically focusing on the area up to 25 feet above the flame source, typically at ground grade This assessment is essential for various classes of vessels that may operate partially full, as outlined in Table 4, which provides recommended liquid inventory portions for calculations Areas above 25 feet and vessel heads protected by support skirts with limited ventilation are generally excluded from the wetted area determination.

Table 4-Effects of Fire on the Wetted Surfaces of a

Class of Vessel Portion of Liquid Inventory Remarks Liquid-full, such as treaters Surge drums, knockout drums, process vessels Fractionating columns

All up to the height of 25 feet -

Normal operating level up to the height of 25 feet -

Normal level in bottom plus liquid holdup from all trays dumped to the normal level in the column bottom; total wetted surface up to the height of 25 feet

Maximum inventory level up to the height of 25 feet (portions of the wetted area in contact with founda- tions or the ground are normally excluded)

Up to the maximum horizontal diameter or up to the height of 25 feet; whichever is greater

Level in reboiler is to be included if the reboiler is an integral part of the column For tanks of

15 psig operating pressure or less; see

Relieving temperatures often exceed the design temperature of the protected equipment, necessitating additional protective measures if elevated temperatures risk vessel rupture In cases where fire exposure leads to vapor generation from thermal cracking, alternative sizing methods may be required For spheres, the wetted area typically encompasses all areas up to the maximum diameter, and it may be beneficial to include a percentage of the vessel area to account for vapor generation in associated piping.

3.15.1.2 Effect of Fire on the Unwetted

Unwetted wall vessels are defined as vessels with internal walls that are exposed to gases, vapors, or super-critical fluids, or are insulated from the inside, regardless of the fluids they contain These vessels can hold separate liquid and vapor phases under normal conditions but transition to a single phase when subjected to relieving conditions above the critical point.

Vessels can be engineered with internal insulation, which is defined by the potential for the internal wall to become insulated through the accumulation of coke or other materials from the fluids contained within.

Wetted surfaces may experience relieving temperatures that exceed the equipment's design temperature If these elevated temperatures pose a risk of vessel rupture, it is essential to explore additional protective measures (refer to sections 3.15.4 and 3.15.5).

3.15.1.2.2 A characteristic of a vessel with an unwetted internal wall is that heat flow from the wall to the contained

In pressure-relieving and depressurizing systems, the resistance of the contained fluid or internal insulating materials can lead to low fluid levels An unwetted vessel's outer surface, when exposed to an open fire, can heat up significantly over time, potentially causing rupture Figures 1 and 2 demonstrate the rapid temperature increase in unwetted vessel walls, with a 1-inch thick steel plate reaching approximately 1,100°F in about 12 minutes and 1,300°F in around 17 minutes when subjected to open flames.

Figure 2 illustrates the impact of overheating ASTM A 515, Grade 70 steel, revealing that an unwetted steel vessel will rupture in approximately 7 hours at 1,100°F under a stress of 15,000 pounds per square inch, while at 1,300°F, the rupture time decreases significantly to about 2.5 minutes.

Figure 1-Average Rate of Heating Steel Plates Exposed to Open Gasoline Fire on One Side

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Time for rupture (hours at indicated temperature)

Figure 2-Effect of Overheating Steel (ASTM A 515, Grade 79)

The heat absorbed by a vessel exposed to an open fire is significantly influenced by the type of fuel used, the extent to which the flames envelop the vessel—determined by its size and shape—and the effectiveness of fireproofing measures.

(Equations 2 and 3) are used to evaluate these conditions where there are prompt firefighting efforts and drainage of flammable materials away from the vessels

Effective drainage is essential for managing the spread of significant spills and controlling surface drainage and refinery wastewater This can be achieved through the strategic implementation of sewers and trenches with sufficient capacity, as well as by utilizing the natural slope of the terrain.

Where adequate drainage and firefighting equipment do not exist, Equation 4 should be used [lo]

Where: q = average unit heat absorption, in British thermal units per hour per square foot of wetted surface

Q = total heat absorption (input) to the wetted surface, in British thermal units per hour

F = environment factor (Values for various types of installation are shown in Table 5.)

The total wetted surface area, denoted as A in square feet, is crucial for understanding fire exposure risks The area exposure factor, represented by the expression A-O.IR or l/AO-'K, highlights that larger vessels are less likely to be fully exposed to flames compared to smaller vessels.

The heat absorption equations provided are applicable to process vessels and pressurized storage of liquefied gases For other storage types, including pressure vessels or tanks with a design pressure of 15 pounds per square inch gauge or lower, refer to API Standard 2000 for recommended heat absorption rates in the event of external fire exposure.

3.15.2.1.2 See 3.15.1.2 for a discussion of the effect of fire on the unwetted surface of a vessel

The discharge areas for pressure relief devices on vessels containing super-critical fluids, gases, or vapors exposed to open fires can be estimated using Equation 5, without accounting for insulation However, insulation credit can be applied as outlined in Table 5.

A = effective discharge area of the valve, in square

A' = exposed surface area of the vessel, in square feet inches

PI = upstream relieving pressure, in pounds per square inch absolute This is the set pressure plus the allowable overpressure plus the atmospheric pressure

F' can be determined from the following relationship The recommended minimum value of F is 0.01; when the minimum value is unknown, F' = 0.045 should be used (See Equa- tion 6)

Where: k = Cp/Cv, the specific heat ratio of gas or vapor (See K,, = coefficient of discharge (obtainable from the valve

API Recommended Practice 520, Part I) manufacturer) K,, is equal to 0.975 for sizing relief Table 5-Environment Factor

Insulated vesselb (With insulation conductance values for fire exposure conditions as follows in British thermal units per hour per square foot per degree Fahrenheit):

Water-application facilities, on bare vesselc 1 o"

The suggested values for the conditions outlined in section 3.15.2 should be applied, and in their absence, engineering judgment is necessary to either select a higher factor or implement protective measures against fire exposure as indicated in sections 3.15.4 and 3.15.5 Insulation must be designed to withstand dislodgment from fire hose streams, as specified in section 3.15.5.2 For the examples provided, a temperature difference of 1,600°F was utilized, with conductance values calculated from Equation 9, based on insulation with a thermal conductivity of 4 BTU-in/hr-ft²-°F at 1,000°F, corresponding to insulation thicknesses ranging from 1 inch to 12 inches Refer to Equation 9 for the determination of F.

In calculating heat input for noninsulated vessels, the environment factor, F, in Equations 3 and 4 should be replaced with 1.0, as it does not apply to these types of vessels For further guidance, refer to API Recommended Practice 520, Part 1.

T, = vessel wall temperature, in degrees Rankine

TI = gas temperature, absolute, in degrees Rankinc, at the upstream relieving pressure, determined from the following relationship:

P, = normal operating gas pressure, in pounds pcr square

T, = normal operating gas temperature, in degrees

OpeningManualValves

When a manual valve is accidentally opened, leading to pressure buildup in a vessel, it is essential that the vessel is equipped with a pressure relief valve capable of handling a flow rate equal to that of the open valve, accounting for any operational alternative outlets The manual valve should be treated as fully open, with the vessel pressure at relief conditions In cases where the manual valve allows a liquid that can flash or a fluid that vaporizes the vessel contents, volumetric or heat-content equivalents may be applied It is important to evaluate only one inadvertently opened manual valve at a time.

Determining the relieving requirements due to power failures necessitates a thorough analysis of the plant or system to identify affected equipment and assess the impact on operations It is essential to carefully review the information in sections 2.3.5 and 2.3.6 While automatic standby systems can enhance on-stream time, reduce unit upsets, and maintain production rates, the reliability of the associated circuitry, sequences, and components is currently insufficient to be factored into the calculation of individual relieving requirements.

Electric power failures can be categorized into three types: local power failures, where a single piece of equipment is impacted; intermediate power failures, affecting a distribution center, motor control center, or bus; and total power failures, which disrupt all electrically operated equipment at once.

Local power failures can significantly impact equipment like pumps, fans, and solenoid valves, with detailed effects discussed in other sections of this practice Once the cause of the failure is addressed, the necessary relieving requirements can be assessed For instance, a pump failure may lead to a loss of cooling water or reflux, with specific details found in sections 3.6 and 3.7 Intermediate power failures can have more severe consequences, potentially resulting in simultaneous loss of all fans at an air cooler and reflux pumps, which could flood the condenser and negate any benefits from natural convection in the air condenser.

Total power failure requires additional study to analyze and evaluate the combined effects of multiple equipment failures

Special consideration should be given to the effect of the simultaneous opening of relief valves in several services, particularly if the relief valves discharge into a closed header system.

Electric Power Failure

Determining the relieving requirements due to power failures necessitates a thorough analysis of the plant or system to identify the affected equipment and its impact on operations It is essential to carefully review the information in sections 2.3.5 and 2.3.6 While automatic standby systems can enhance on-stream time, reduce unit upsets, and maintain production rates, the reliability of the associated circuitry, sequences, and components is not yet adequate to be credited in defining individual relieving requirements.

Electric power failures can be categorized into three types: local power failures, which impact a single piece of equipment; intermediate power failures, affecting a distribution center, motor control center, or bus; and total power failures, where all electrically operated equipment is affected simultaneously.

Local power failures can significantly impact equipment like pumps, fans, and solenoid valves, with detailed effects discussed in other sections of this practice Once the cause of the failure is addressed, the necessary relief requirements can be assessed For instance, a pump failure may lead to a loss of cooling water or reflux, with specific details found in section 3.6, while loss of absorbent is addressed in section 3.7 Intermediate power failures can have more severe consequences, as simultaneous loss of all fans at an air cooler and reflux pumps may occur, potentially flooding the condenser and negating any benefits from natural convection in the air condenser.

Total power failure requires additional study to analyze and evaluate the combined effects of multiple equipment failures

Special consideration should be given to the effect of the simultaneous opening of relief valves in several services, particularly if the relief valves discharge into a closed header system

The ASME Code, Section VIII, Division 1, Paragraph UG-

According to section 133(d), heat exchangers and similar vessels must be equipped with a relieving device capable of preventing overpressure in the event of an internal failure This requirement highlights several key issues: first, identifying the types and extent of potential internal failures; second, calculating the necessary relieving capacity; third, choosing a device that responds quickly enough to avert overpressure; and finally, determining the optimal location for the device to ensure timely detection and reaction to overpressure conditions.

Complete tube rupture, while a rare event, can lead to a significant flow of high-pressure fluid to the lower pressure side of an exchanger Minor leaks typically do not cause overpressure during operation Given that standard hydrostatic test pressure is set at 150% of the equipment's design pressure, the likelihood of equipment failure due to a tube rupture is low, especially if the low-pressure side is designed to withstand at least two-thirds of the high-pressure side's design pressure In certain cases, it may be appropriate to use the maximum system pressure as the design pressure for the high-pressure side, particularly when there is a notable difference between the design and operating pressures.

When the actual test pressure on the low-pressure side is below 150 percent of the design pressure, this lower pressure should be assessed to determine the necessity of overpressure protection Additionally, pressure relief for tube rupture is unnecessary if the low-pressure exchanger side, including both upstream and downstream systems, meets or exceeds the two-thirds design criteria.

Increasing the design pressure on the low-pressure side in new installations can help mitigate risks It is essential to conduct a comprehensive evaluation of the upstream and downstream piping and equipment systems when implementing this containment strategy.

3.18.3 DETERMININGTHE REQUIRED RELIEF FLOW RATE

Internal failures can range from minor pinhole leaks to complete tube ruptures To determine the necessary relieving flow rate, it is essential to consider that the failure involves a sharp break in a single tube, occurs at the back side of the tubesheet, and allows high-pressure fluid to flow through both the remaining tube stub in the tubesheet and the longer section of the tube.

Using a simplifying assumption of two orifices can yield a higher relief flow rate compared to the method involving a long open tube and tube stub.

When calculating the relief rate, it is essential to consider any liquid that may vaporize due to pressure reduction or, in the case of volatile fluids being heated, the combined effects of pressure reduction and vaporization from contact with hotter materials on the low-pressure side.

For liquids that do not vaporize upon passing through an opening, the discharge rate should be calculated using incompressible flow formulas In contrast, for vapor flowing through a ruptured tube opening, compressible flow theories are applicable Steady-state equations for determining the flow rate through an orifice or open tube end for gas or non-flashing liquid services can be found in Cranc Technical Paper No 410 or other fluid flow references.

To accurately determine the flow rate through failures involving flashing liquids or two-phase fluids, a two-phase flow method is essential The flow models created by DIERS and others can be effectively adapted for this application For more detailed information on these models, please refer to the relevant literature.

There are two methods for determining the appropriate size of a relief device: steady-state analysis and dynamic analysis The steady-state method relies on the flow rate of gas or liquid through the rupture to size the relief device, allowing for capacity credit from low-pressure side piping as outlined in section 3.18.5 In contrast, the dynamic approach models the pressure profile and transients in the exchanger following a rupture event.

24 API RECOMMENDED PRACTICE 521 ture, and generally will include the response time of the relief device

This analysis is essential when there is a significant pressure difference between the two sides of an exchanger, particularly when the low-pressure side is liquid-full and the high-pressure side contains a gas or fluid that may flash during a rupture Modeling indicates that transient conditions in these scenarios can lead to considerable overpressure, even with the presence of a pressure relief device.

Vapor Depressuring

Elevated metal temperatures beyond the designated design limits, caused by fire or exothermic reactions, can lead to stress rupture, even if system pressure remains within allowable limits To prevent this risk, vapor depressuring is an effective strategy When both fire and process conditions necessitate vapor depressuring, the more significant requirement should dictate the capacity of the depressuring facilities.

A vapor depressuring system must have sufficient capacity to reduce vessel stress to a safe level, minimizing the risk of stress rupture Typically, this involves lowering the equipment pressure to 50 percent of the vessel's design pressure within about 15 minutes This guideline is applicable to vessels with wall thicknesses of approximately 1 inch (25 millimeters) or more, while thinner-walled vessels may require a faster depressuring rate The necessary depressuring rate is influenced by factors such as the vessel's metallurgy, wall thickness, initial temperature, and heat input rate.

Many light hydrocarbons will chill to low temperatures as pressure is reduced Design and depressuring conditions should consider this possibility

Depressuring is expected to persist throughout the emergency, ensuring that the valves remain functional or fail in a fully open position during this time.

Fireproofing of the power supply and valve actuator may be required in a fire zone

Where fire is controlling, it may be appropriate to limit the application of vapor depressuring to facilities that operate at

For equipment operating at 250 pounds per square inch gauge (1,724 kilopascals gauge) and above, it is crucial to consider the size and volume of the contents An effective alternative is to depressurize all equipment handling light hydrocarbons, aiming to reach a pressure of 100 pounds per square inch gauge (690 kilopascals) or 50 percent of the vessel's design pressure, whichever is lower, within 15 minutes This reduced operating pressure facilitates quicker control in scenarios where a fire source may arise from the leakage of flammable materials Further details on the impact of heat input to process vessels can be found in sections 3.15.2 and 3.19.2.

If the temperature rise is from a chemical reaction, refer to

3.13 for guidance on how to estimate the vent size and temperature rise in a reactive system

To effectively lower internal pressure in fire-affected equipment, it is essential to remove vapor at a rate that addresses several factors: the vapor produced from liquid due to heat from the fire, the change in density of the internal vapor as pressure decreases, and the occurrence of liquid flash resulting from pressure reduction, particularly when the system contains liquid near its saturation temperature.

The total vapor load for a depressured system can be calculated by summing the individual contributions from all involved equipment, specifically considering the loads outlined in Items a-c.

Wr = Item a + Item b + Item c and is expressed by Equation

Note: The variables for all equations in this section are defined in 3.19.3

The expression Wt is utilized to represent a flow rate per unit of time, while certain vapor quantities, such as Wdt and W,t, are mass quantities unaffected by time When depressuring a system with multiple vessels, it is crucial to calculate the vapor quantities for each vessel, considering variations in molecular weights, latent heats, insulation thicknesses, and vaporization temperatures The average molecular weight and temperature for Wt, which denotes the total vapor released from the entire system, should be derived from the individual vapor molecular weights and temperatures The vapor loading on the depressuring system for each term in Equation 10 can be estimated in sections 3.19.2.2 through 3.19.2.4.

3.19.2.2 Vapor From Fire Heat Input

When calculating heat input to equipment during a fire, modifications for vapor depressuring and pressure-relieving systems must be considered The size of the assumed fire zone, typically around 2,500 square feet (232 square meters), is crucial, as it generally does not impact the design of main relief headers in processing areas Additionally, increasing insulation thickness on vessels can help reduce vapor generation from fire exposure It is important to note that during a fire, all feed and output streams, as well as internal heat sources, are assumed to have stopped, making vapor generation dependent solely on heat absorbed from the fire and the latent heat of the liquid.

To determine the vapor load produced by a fire, it is essential to assume that the fire continues throughout the depressurizing period The vapor weight generated during this interval in a vessel, denoted as \(i\), can be calculated using Equation 1.

This calculation should be repeated for all vessels in the system if significant differences in vapor and liquid properties are involved

3.19.2.3 Vapor From Density Change and Liquid

Calculating vapor loads from changes in vapor density and liquid flash cannot be entirely separated To accurately assess the vapor quantities from these factors, it is essential to know the liquid inventory and vapor volume within the system This includes all liquid and vapor in directly connected facilities outside the fire area that cannot be isolated during a fire, as well as all liquid and vapor present in equipment within the assumed fire area.

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To estimate liquid inventory in fractionating columns, consider the normal column bottom and draw-off tray capacity, adding a holdup per tray equal to the weir height plus 2 inches (50 millimeters) or its known design quantity For accumulators, use normal operating levels as the basis for inventory calculations Additionally, for a quick approximation of standard shell-and-tube heat exchangers, assume that one-third of the total shell volume is occupied by the tube bundle.

In vaporizing service for condensers and heat exchangers, it is essential to assume that 80 percent of the involved volume is vapor, with the remaining 20 percent as liquid Additionally, all liquid present in heaters must be accounted for in the estimates, irrespective of temperature For heaters operating in vaporizing service, it is recommended to consider 80 percent of the tube volume beyond the normal vaporization point as vapor.

Only after the vapor and liquid volumes in the system have been determined can one estimate the respective loadings they contribute to depressuring

To calculate the weight of vapor that needs to be removed from a vessel's vapor space to offset the decrease in vapor density at lower pressure, one can utilize Equation 12 or Equation 13.

Note: C: is assumed not to increase significantly as a result of liquid flash

This calculation should be repeated for each vessel in the system if different vapor properties are involved

The calculation of vapor load resulting from liquid flash is influenced by both the quantity and properties of the liquid in the system, making the preceding data relevant for this assessment.

Special Considerations for Individual Valves

Sizing procedures for pressure safety valves are covered in API Recommended Practice 520, Part I, with the exception of the circumstances covered in 3.20.1 through 3.20.3

3.20.1 LIQUID-VAPOR MIXTURE AND SOLIDS

A pressure relief valve managing a liquid at vapor-liquid equilibrium or a mixed-phase fluid can generate vapor due to flashing, which may decrease the valve's effective mass flow capacity It is essential to consider the potential for liquid carryover caused by foaming or insufficient vapor-liquid disengagement Designers should examine the implications of flow reduction or choking, which occurs when the pressure-drop increment is fully utilized to accelerate the flashing fluid, leaving no pressure difference to counteract friction in the line For more detailed guidance, refer to API Recommended Practice 520, Part I, and additional references Furthermore, certain fluids, such as carbon dioxide and wet propane, may form solids upon discharge through the relief device, and no widely accepted method exists to mitigate the risk of plugging.

STD.API/PETRO RP 521-ENGL 1777 M 0732290 05b395L 334

Figure 3-Equilibrium Phase Diagram for a Given Liquid

DEVICE IN A NORMALLY LIQUID SYSTEM

When sizing valves or devices to manage vapor release in a typically all-liquid system, it is crucial to position them correctly to ensure they effectively relieve vapor rather than having to handle the equivalent volume of vapor as liquid.

By virtue of its broad use as a reference or base code, the

The ASME Code serves as the authoritative standard for the minimum safety and performance requirements of safety and relief valves While other regulations may apply in specific contexts or installations, they do not always align with the ASME Code concerning the sizing, application, setting, and utilization of relief devices.

The ASME Code, Section VIII, is essential for understanding the installation of multiple-pressure relief valves, whether they have staggered set pressures or not.

Division 1, Paragraph UG-125 through Paragraph UG-136,

Steam-generating equipment must be constructed in compliance with Section I of the ASME Code and should be adequately protected as per the requirements of that code, which is not covered in this recommended practice.

A multiple-valve installation with staggered settings is advantageous due to several key factors, including optimal sizing, reduced valve leakage, compliance with pressure vessel requirements, and the inlet pressure characteristics of the pressure relief valve Additionally, it accounts for reactive thrust during relief and accommodates a range of relieving rates for different scenarios.

When sizing pressure relief valves, it is essential for designers to identify potential overpressure sources, determine the governing flow rate, and select the appropriate orifice area Due to the unpredictability of simultaneous overpressure events, conservative sizing often leads to oversizing As process units grow larger, the required orifice area may exceed what a single valve can provide, necessitating the use of multiple valves to manage capacity Minor pressure fluctuations in the controlled vessel can cause continuous leakage until the system pressure drops enough for the valve to close Larger valves tend to have lower lift capabilities for small flow rates, resulting in increased leakage and potential seat damage This issue is exacerbated when multiple valves are uniformly set, but staggered settings may offer a solution Ideally, the smallest valve should be set at the lowest pressure, addressing a reasonable portion of the total relieving requirement, while higher set valves activate only when the combined orifice areas are needed to manage the flow.

The design requirements for pressure vessels are determined by the process's pressure conditions, operational pressure relief needs, and the specifications outlined in Section VIII of the ASME Code, as shown in Figure 4 The maximum allowable working pressure is the critical baseline, representing the highest pressure at which the primary pressure relief valve is set to open There is flexibility in determining set pressures within the established limits.

The inlet pressure characteristics of pressure relief valves are depicted in Figure 4, highlighting the typical installation on processing pressure vessels It also addresses the specific scenario of a supplemental valve designed to handle unexpected external heat, such as fire conditions To ensure optimal performance, it is crucial to prevent inlet starvation to the pressure relief valve by minimizing flow losses due to friction, in accordance with API Recommended Practice 520, Part 11.

The maximum probable mechanical stresses and forces from discharge flow through a pressure relief valve are outlined in API Recommended Practice 520, Part 11 This guidance focuses on steady-state conditions rather than the instantaneous forces occurring when the valve initially opens Both impact and adjustment forces arise as the inlet and outlet piping strive for force equilibrium under relieving pressure and temperature conditions The situation becomes more complex when multiple valves operate simultaneously, as the orifices must be sized for the largest relief quantity, increasing the likelihood of on-off action (chatter) in uniformly set multiple valves or a single large valve.

Utilizing multiple valves can be achieved efficiently and cost-effectively within the ASME Code's parameters According to API Recommended Practice 520, Part I, it is essential to refer to the permissible value of P, the pressure for relief valve sizing, which outlines the set pressure staggering permitted by the ASME Code for both operational and fire scenarios When assessing multiple safety relief valve discharges, it is crucial to evaluate the impact of back pressure with all valves operating simultaneously under a single contingency Typically, the design strategy involves considering all safety relief valves in flow.

Pressure Vessel Requirements Typical Characteristics of

Maximum allowable accumulated pressure Maximum relieving pressure

(fire exposure only) for fire sizing

Maximum allowable accumulated pressure for multiple-valve installation

(other than fire exposure) Multiple valves

Maximum relieving pressure for process sizing

Margin of safety due to orifice r Single valve

Maximum allowable accumulated pressure for supplemental valves for single-valve installation Y

- a - cn Maximum allowable set pressure

Maximum allowable working pressure or design pressure c

Simmer 1, for single valve (average)

Not specified by Section Vlll Tightness: API Standard 527

1 , The operating pressure may be any lower pressure required

2 The set pressure and all other values related to it may be moved downward if the operating pressure permits

3 This figure conforms with the requirements of Section VIII, Division 1, of the ASME Code

4 The pressure conditions shown are for safety relief valves installed on a pressure vessel (vapor phase)

In pressure-relieving and depressuring systems, it is crucial to manage the simultaneous operation of staggered set valves on a single vessel or multiple safety relief valves across different vessels during a contingency The overall flow rate significantly influences the back pressure within the system.

An increase in back pressure due to contingencies is classified as built-up back pressure When using conventional valves, any pressure rise on the discharge side must adhere to the limitations outlined in API Recommended Practice 520, Part I Within these constraints, variations in back pressure from the sequential opening of valves do not need to be regarded as superimposed back pressure affecting other valves.

References

I NFPA 68, Guide for Venting Deflagrations, National Fire

2 NFPA 69, Explosion Prevention Systems, National Fire

3 M A Grolmes, J C Leung, and H K Fauske, “Reactive

Systems Vent Sizing Evaluations” International Symposium on Runaway Reactions, March 7-9, 1989, Cambridge, Mas- sachusetts, pp 451-476

4 H G Fisher, et al, “Emergency Relief System Design

Using DIERS Technology,” American Institute of Chemical

5 H G Fisher, “An Overview of Emergency Relief System

Design Practice,” Plant Operations Progress, January 1991

6 J C Leung, “Overpressure During Emergency Relief

Venting in Bubbly and Churn Turbulent Flow,” AIChE Jour- nal, Volume 33, Number 6, June 1987

7 J C Leung, “Simplified Vent Sizing Equations for Emer- gency Relief Requirements in Reactors and Storage Vessels,”

AZChE Journal, Volume 32, Number 10, October 1986

8 Cyril F Parry, Relief Systems Handbook, Institution of

9 H R Wharton, “Digest of Steels for High-Temperature

10 F J Heller, “Safety Relief Valve Sizing: API Versus CGA

Requirements Plus a New Concept for Tank Cars,” 1983 Pro- ceedings-Refining Department, Volume 62, American

11 J J Duggan, C H Gilmour, and P F Fisher, “Require- ments for Relief of Overpressure in Vessels Exposed to Fire,”

Transactions of the ASME, 1944, Volume 66, pp 1-53

12 I Heitner, T Trautmauis, and M Morrissey, “Relieving

Requirements for Gas Filled Vessels Exposed to Fire,” 1983

Proceedings-Refining Department, Volume 62, American

13 I 0 Francis and W E Shackelton, “A Calculation of Relieving Requirements in the Critical Region,” 1985 Proceedings-Rejining Department, Volume 64, Ameri- can Petroleum Institute, pp 179-182

14 ASTM C-533-85, Standard Specification for Calcium Sil- icate Block and Pipe Thermal Insulation, Reapproved 1990

15 ASTM C-592-80, Mineral Fiber Blanket Insulation and

Blanket-Type Pipe Insulation (Metal Mesh CoveredJ (Indus- trial Type), American Society for Testing Materials Dallas, Texas

16 ASTM C-612-93, Standard Specifications for Mineral

Fiber Block and Board Thermal Insulation, (Type 111, Type ll? and Type V), American Society for Testing Materials, Dallas, Texas

17 ASTM C-552-91, Standard Spec@cation for Cellular

Glass T h e m 1 Insulation, American Society for Testing Materials, Dallas, Texas

18 ASTM C-610-95, Molded Expanded Perlite Block and Pipe Thermal Insulation, American Society for Testing Mate- rials, Dallas, Texas

19 ASTM C-1086-90a, Glass Fiber Felt Thermal Insulation,

American Society for Testing Materials, Dallas, Texas

20 T Z Harmathy and L W Allen, “Thermal Properties of Selected Masonry Unit Concretes, Title Number 70- 15,” ACl Journal, February 1973

21 P P M Brown and D W France, “How to Protect Air Cooled Exchangers from Overpressure,” Hydrocarbon Pro- cessing, August 1975

22 Crane Engineering Division Technical Paper 410, “Flow of Fluids Through Valves, Fittings, and Pipe.”

23 J C Leung, “Size Safety Relief Valves for Flashing Liq- uids,” Chemical Engineering Progress, February, 1992

24 J C Leung, and F N Nazario, “Two-Phase Flashing Flow Methods and Comparison,” Journal of Loss Prevention Process Industries, Volume 3, Number 2, 1990

25 D W Fowler, T R Herndon, and R C Wahrmund, “An Analysis of Potential Overpressure of Heat Exchanger Shell Due to a Ruptured Tube,” Paper presented at the American Society of Mechanical Engineers Petroleum Division Confer- ence, September 22-25,1968

26 V H Sumaria, J A Rovnak, I Heitner, and R J Herbert,

“Model to Predict Transient Consequences of a Heat Exchanger Tube Rupture,” Proceedings-Refining Depart- ment, 1976, Volume 55, American Petroleum Institute, Wash- ington, D.C., pp 631-654

27 L L Simpson, “Estimate Two-Phase Flow in Safety Devices,” Chemical Engineering, August 199 1

28 H K Fauske, et al, “Emergency Relief Vent Sizing for Fire Emergencies Involving Liquid Filled Atmospheric Stor- age Vessels,” Plant Operations Progress, Volume 5 , Number

OF DISPOSAL SYSTEMS

SYSTEMS

Tiêu đề	Guide for Pressure-Relieving and Depressuring Systems
Tác giả	American Petroleum Institute
Trường học	American Petroleum Institute
Chuyên ngành	Petroleum Engineering
Thể loại	Standard
Năm xuất bản	1997
Thành phố	Washington, D.C.

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Số trang	113
Dung lượng	8,27 MB