1 Introduction

Overpressure is caused by the accumulation of material or energy within a process system that exceeds the design conditions of the equipment. Relief of this overpressure in a plant is an ASME Code requirement and is necessary for loss minimization, energy conservation, and the protection of operating personnel, the public, the environment, and other nearby equipment.

2 Applicable Codes and Standards

2.1 Legal Requirements

The leading document is by the U.S. Department of Labor’s Occupational Safety & Health Administration (OSHA) in OSHA 1910.119, “Process Safety Management of Highly Hazardous Chemicals.” Next comes the Boiler and Pressure Vessel Code from the American Society of Mechanical Engineers (ASME). Local codes and requirements are in effect too. Texas has its Boiler Law. There’s NFPA 30, the Flammable and Combustible Liquids Code. OSHA also has OSHA 1910.106 for Flammable Liquids. ASME also has ASME/ANSI B31.3, the Chemical Plant and Refinery Piping Code. Lastly, there’s the Uniform Building Code for systems inside buildings.

2.2 Industry Standards

The most common industry standards for relief systems come from the American Petroleum Institute. Most well-known are API RP 520 and API STD 521. For non-refinery systems, the standards from the National Fire Protection Agency (NFPA) are usually followed. The American Institute of Chemical Engineers has their manuals also. Additionally, many companies have their own internal standards and preferred practices.

3 Pressures

3.1 Pressure Definitions

Operating Pressure – the gage pressure to which the equipment is normally subjected to in service.
Design Pressure – the pressure in the equipment or piping under consideration at the most severe combination of coincident pressure, temperature, liquid level, and vessel pressure drop during service, which results in the greatest required component thickness and the highest component rating.
Maximum Allowable Working Pressure – For pressure vessels, the maximum allowable working pressure (MAWP) is the maximum gage pressure permissible at the top of a vessel in its normal operating position at the designated coincident temperature and liquid level specified for that pressure. MAWP does not apply to piping. Design pressure is equal to or less than the MAWP. If MAWP is unknown, replace MAWP with the design pressure.
Set Pressure – the inlet gage pressure at which the pressure-relief valve (PRV) is adjusted to open under service conditions.
Overpressure – the pressure increase over the set pressure of the relieving device during discharge.
Accumulation – the pressure increase over the MAWP or design pressure of the vessel during discharge through the relief device expressed as a percent of that pressure.
Relieving Pressure – the inlet absolute pressure to a pressure-relief device at a specified overpressure

3.2 Set Pressure Recommendations

The recommended pressure that the pressure-relief device must open under service is defined by several codes, and is listed in the following table.

ASME Code Section VIII Division 1 Pressure Vessels (Process Upset)
Single Relief Device	P_SET ≤ P_MAWP
Multiple Parallel Devices First Device	P_SET ≤ P_MAWP
Later Devices	P_SET ≤ 1.05 × P_MAWP
ASME Code Section VIII Division 1 Pressure Vessels (External Fire)
Multiple Parallel Devices First Device	P_SET ≤ P_MAWP
Later Devices	P_SET ≤ 1.10 × P_MAWP
Piping per ASME/ANSI B31.3
All except thermal expansion	P_SET ≤ P_Design
Thermal expansion of blocked-in pipe	P_SET ≤ 1.20 × P_Design

Table 1 – Set Pressure Recommendations

3.3 Allowable Pressures during Relief

These are the maximum allowable pressures that equipment can experience during an overpressure event. The following table lists requirements from several different codes.

ASME Code Section VIII Division 1 Pressure Vessels (Process Upset)
Single Relief Device	1.10 × P_MAWP or 3 psig, whichever is greater
Multiple Parallel Devices	1.16 × P_MAWP or 4 psig, whichever is greater
ASME Code Section VIII Division 1 Pressure Vessels (External Fire)
One or More Relief Devices	1.21 × P_MAWP
Piping per ASME/ANSI B31.3
Overpressure lasting less than ten hours per event and less than 100 hours per year total for all events	1.33 × P_Design
Overpressure lasting less than 50 hours per event and less than 500 hours per year total for all events	1.20 × P_Design

Table 2 – Allowable Pressures during Relief

4 Pressure Relief Devices

A pressure-relief device is either a relief valve, a bursting (rupture) disc, or a combination of both. There are also explosion vents, hydraulic accumulators, goose-neck vents, and vapor-depressuring systems.

4.1 Types of Relief Devices

4.1.1 Rupture Discs

A rupture-disc device is actuated by inlet static pressure and is designed to function by the bursting of a pressure-retaining diaphragm or disc. It is designed to withstand pressure up to a specified level, at which it will fail and release the pressure from the system being protected. The design, manufacture, and testing of rupture discs is regulated by the ASME Code. The burst pressure of rupture discs is strongly affected by its temperature. In general, the burst pressure decreases with increasing temperature. The most common type of rupture disc fits between standard flanges. The following figure shows a rupture disc before and after bursting.

Figure 1 – Rupture Disc (from API RP 520, Part 1)

4.1.2 Relief Valves

Relief valves are normally the first choice for overpressure protection due to their reliability, ruggedness, and reclosing feature. An ASME Code stamp indicates the PRV has gone through a certification process to ensure flow capacity and opening within tolerances.

4.1.2.1 Spring-Loaded Pressure-Relief Valves

4.1.2.1.1 Conventional Spring Loaded Pressure-Relief Valves

A conventional PRV is vented to the discharge side and is therefore unbalanced. Performance characteristics (i.e., opening pressure, closing pressure, lift, and relieving capacity) are directly affected by the back pressure on the valve. A typical conventional PRV is shown in the following figure.

Figure 2 – Conventional Pressure Relief Valve with Threaded Connections (from API RP520, Part 1)

4.1.2.1.2 Balanced Bellows Spring Loaded Pressure-Relief Valves

This is a PRV that incorporates a vented bellows as a means of minimizing the effect of back pressure on the performance characteristics.

4.1.2.2 Pilot-Operated Pressure-Relief Valves

A pilot-operated PRV has the major flow device combined with, and controlled by, a self-actuated PRV. This type of valve does not utilize and external source of energy and is balanced if the auxiliary PRV is vented to the atmosphere. A typical pilot-operated PRV installation is shown in the following figure.

Figure 3 – Pilot Operated Pressure Relief Valve (from API RP 520, Part 2)

4.1.2.3 Standard Relief Valve Orifice Sizes

The orifice sizes for relief valves have been standardized by both the American Petroleum Institute (API) and the American Society of Mechanical Engineers (ASME). The orifice letter designations and sizes are listed in the following table.

Orifice Label	API Effective Area (in²)	Actual ASME Area (in²)
D	0.110	0.150
E	0.196	0.226
F	0.307	0.371
G	0.503	0.559
H	0.785	0.873
J	1.287	1.430
K	1.838	2.042
L	2.853	3.170
M	3.60	4.00
N	4.34	4.822
P	6.38	7.087
Q	11.05	12.27
R	16.0	17.78
T	26.0	28.94
U	NA	31.50

Table 3 – Standard Orifice Designations

4.1.2.4 Relief Valve Orifice/Body Size Combinations

Standard-size relief valves are available in specific orifice area and body-size (inlet × outlet) combinations. These are shown on the following table.

Orifice Label	Valve Body Size (inlet diameter × outlet diameter), inches
	1×2	1½×2	1½×2½	1½×3	2×3	2½×4	3×4	4×6	6×8	6×10	8×10
D	X	X	X
E	X	X	X
F	X	X	X
G			X	X	X
H				X	X
J					X	X	X
K							X
L							X	X
M								X
N								X
P								X
Q									X
R									X	X
T											X

Table 4 – Relief Valve Body/Orifice Combinations

4.1.3 Rupture Disc/Relief Valve Combinations

Rupture discs are sometimes installed immediately upstream or downstream of a PRV. They serve to isolate the PRV from the contents of the upstream or downstream piping. A typical installation is shown in the following figure.

Figure 4 – Rupture Disc / Relief Valve Combination (from API RP 520, Part 2)

4.2 Location of Relief Devices

Relief devices are commonly found at the following locations.

Isolated equipment items
Cold outlet of heat exchangers before the block valve
Closed piping systems exposed to heating
Discharge of reciprocating compressors before the block valve
Discharge of positive-displacement pumps before the block valve
Outlet side of fired heaters
Between the block valves on low-pressure sides of heat exchangers
Outlets of turbines
As close as possible to equipment being protected

5 Sequence for Relief Sizing

The design sequence for relief sizing is typically derived from the following steps:

Define the process conditions at the time of the initiation of a proposed emergency event.
Track the course of the event by calculations or logic exercises to the point of the most severe venting conditions or to the maximum allowable pressure level of the equipment.
List all possible maloperations and system failures for which emergency relief may be required.
Put the emergency-relief device set pressure at or below the vessel MAWP, depending on the anticipated pressure profile of the selected scenario.
Determine the vent rate that will just prevent the pressure from rising above the maximum allowable venting pressure for the equipment (e., the minimum required relief capacity).
Select a standard-size relief device to have at least this much flow.

6 Relieving Scenarios (Plant Upset Conditions)

Process simulation software can be used to simulate the various scenarios.

6.1 Operator Error

Flow blockage
Inadvertent valve opening

6.2 General or Partial Utility Failure

Cooling water
Electric power
Steam or boiler feedwater
Fuel
Plant or instrument air

6.3 Local Equipment or Operation Failure

Reflux
Reboiler
Air-cooled heat exchanger or condenser
Shell & tube heat exchanger or condenser
Fan failure
Accumulation of non-condensibles
Loss of absorbent flow
Automatic process controls

6.4 External Fire

Heat models from API 520/521, API 2000, OSHA 1910.106, and NFPA are used for external fires. These models express the heat absorption in terms of the wetter surface area of the vessel. Each of these codes have unique requirements for how vessel wetted areas are estimated, and how much credit can be taken for environmental factors such as the presence of fire-suppression equipment and thermal insulation.

Once all the rules are applied, the required relieving rate is simply the vaporization rate, which is the heat input divided by the latent heat of vaporization.

6.5 Thermal Relief

Thermal expansion occurs when the cold fluid is blocked in and the hot fluid continues flowing through a heat exchanger.

6.6 Miscellaneous Contingencies

Internal explosion
Chemical reaction
Volatile material in contact with hot liquid
Hydraulic expansion
Transient pressure surges

7 Relief Device Sizing

7.1 Relieving Capacity Requirements

Relief-device equations are based on flow through the orifice at sonic velocity.

The design capacity is the capacity used to determine the required area of a relief device based on the limiting scenario. The rated capacity is the flow that a relief device can pass when fully open at accumulated pressure. This rate is greater than or equal to the design capacity.

For a given system being protected, the general method is to identify the sources of energy, and then to determine how the energy translates into a pressure deviation. Sources of energy can be either heat or fluid sources.

7.2 Relief Device Inlets and Outlets

The applicable codes and standards limit the allowable pressure drops in relief-device inlets and outlets to some fraction of the set pressure. Inlet pressure drops are usually limited to prevent chattering and subsequent damage to the relief valves. Outlet pressure drops are limited to prevent relief-device capacity limitations due to sonic velocity of relief flows at the exit. The inlets and outlet sizes are based on the maximum valve capacity.

Reaction forces must also be calculated (a.k.a., thrust analysis) on the relief-device outlet so that its design is structurally sound.

8 Fire Zones, Fire Circles, and Fire Cylinders

A process plant is divided into fire-risk areas, each of which is the maximum area which can reasonably be expected to be totally engulfed in a single fire. ¶ 7.1.2 of API STD 521 defines these fire-risk areas as 2,500 to 5,000 ft². From that is derived the general requirement that all equipment surfaces contained within an 80-ft diameter and a 25-ft high envelope are considered to be engulfed in a single fire. Thus, the fire circle is defined as having an area of 3,850 ft² and the fire cylinder a volume of 96,200 ft³.

9 Disposal Methods

9.1 Atmospheric Venting

Venting directly to the atmosphere relies upon natural dispersion and jet mixing to reduce the concentration of released material to safe levels. It is usually most economical to vent nontoxic materials (e.g., steam, air, nitrogen) into the atmosphere at a safe location.

9.2 Discharge to Grade or Sewers

This method can generally be used for liquids which are nonhazardous and are not released in large quantities.

9.3 Venting to a Lower-Pressure System

This method is attractive for streams that are unsuitable for grade or atmospheric release and usually does not require construction of collection or treating systems. The impact of doing this on the receiving process must be evaluated.

9.4 Discharge to a Closed Collection System

This system may treat or cool the release stream and either recover some or all of the material or route it to a remote location where it can be safely disposed of. This type of system can be a liquid blowdown system, an incinerator system, a flare system, a burn pit, or a vapor recovery system.

10 Flaring

Flaring, as a disposal method, warrants special consideration. A flare is a combustion device that uses an open flame to burn combustible gases with combustion air provided by uncontrolled ambient air around the flame.

10.1 Safety Issues in Flare Design

10.1.1 Flameout

The pilots are auxiliary burners used to ignite the vent gas routed to the flare. They are on at all times.

A method to monitor the pilot and provide a reliable system to reignite the pilot burner must be provided. A typical flare pilot detection system consists of thermocouples, infrared sensors, acoustic sensors, and ionized-gas detection.

The ignition system must reliably ignite the pilot. Modern techniques include flame-front generators, electrical spark-plug type igniters, and aspirated air igniters. The following figure shows a typical arrangement for an elevated flare.

Figure 5 – Flare Pilot and Purge System (from Center for Chemical Process Safety, 1993)

The following figure shows the details for a flame-front generator.

Figure 6 – Flame Front Generator Details (from API STD 537)

10.1.2 Flashback Protection

The system is subject to explosion hazards if air is present. Air may enter the flare stack when flaring has just ceased and cooling & shrinkage of the gas column draws air in, or if there is condensation within the flare system. In addition, light flare gases (e.g., hydrogen) may leave the pressure at the bottom of the column lower than atmospheric, thus drawing air in. The flare stack itself may create a natural draft and thus draw air in.

Seals are required to prevent air from entering the system. A common one is a molecular seal installed at the flare tip which creates a tortuous path and takes advantage of density differences to keep air out. The most effective seal is the liquid seal, which is simply a head of liquid, usually water that physically prevents air from intruding into the system. The following figure shows a molecular seal.

Figure 7 – Molecular Seal (from API RP-521)

The header system and stack are continuously purged with fuel gas to keep the system above the higher explosive limit (HEL). Corrosive material is also swept away to keep from damaging the system piping.

10.1.3 Burning Liquid Fallout

The knockout drum is designed to separate entrained liquid and to serve as temporary storage for accumulated liquid. Normally, a horizontal drum is selected. A typical flare knockout drum is shown in the following figure.

Figure 8 – Flare Knockout Drum (from API RP 521)

10.1.4 Smoke

Smoke is avoided by using a steam to increase the inspiration and entrainment of air. Steam also cools the flare flame and delays cracking. A typical steam injected smokeless flare tip is shown in the following figure.

Figure 9 – Steam Injected Smokeless Flare Tip (from API RP 521)

10.2 Relief and Flare Headers

Environmental regulations mandate that hydrocarbon effluents be vented to closed systems.

10.2.1 Header Sizing

The sizing of the relief header is done like a typical piping manifold. Simulation of the relief header is necessary to ensure that the vent piping manifold does not restrict the vent flow in the event of coincident relief. The use of process-simulation software is an indispensable aid in the rapid evaluation of these flow systems. Simultaneous PRV releases are considered for worst-case hydraulics. The flow through a component in a piping network is a function of the inlet and outlet pressures, making it three variables. If two of the three variables are specified, the third is dependent. Specifying pressures at various junctions in the piping network allows the system to be represented by a set of dependent equations where flow can be calculated. Balancing flow and pressure in relief manifolds is an extensive trial and error procedure.

10.2.1.1 Back Pressure

Back pressure is the pressure that exists at the outlet of a pressure relief device as a result of the pressure in the discharge system. In sizing relief headers, back pressure must be considered to verify that the relieving capacities of the relief devices are not diminished. The different types of back pressure are the following.

10.2.1.1.1 Superimposed Back Pressure

Superimposed back pressure is the static pressure that exists at the outlet of a pressure relief device prior to lifting as a result of the pressure in the discharge system.

10.2.1.1.2 Built-up Back Pressure

The increase in pressure in the discharge header that develops as a result of flow after the pressure relief device opens.

10.2.1.2 Mach Numbers

Unlike other types of piping systems, there are no definite velocity limitations for sizing flare headers. Normally, keeping velocities under 0.5 Mach will avoid back pressure problems in the header. Flare tips are also sized for a Mach Number of 0.5.

10.2.2 Flare Gas Flow Measurement

The latest codes and standards require some means of monitoring the volume of gas directed to flares. Range and accuracy requirements are best met using ultrasonic flowmeters.

10.2.3 Liquid Drainage

Flare headers are normally sloped to allow free drainage on any liquids into the knockout drum.

10.3 Elevated Flares

The height of an elevated flare is determined by the infrared radiation felt at the ground. The following table gives some guidelines from API RP 521 regarding allowable radiation levels and protection.

Protection	Radiation Level (Btu/hr ft²)
Equipment protection	5,000
Personnel, few seconds escape only	3,000
Personnel, one minute exposure	2,000
Personnel, several minutes short exposure	1,500
Personnel, continuous exposure	500

Table 5 – Design Radiation Levels

10.3.1 Onshore Facilities

Onshore elevated flares are either self-supporting-, guyed, or derrick-supported. Self-supporting stacks are preferred to heights of up to 250 feet, derrick-supported stacks up to 400 feet, and guyed stacks up to 600feet. Anything higher requires a concrete support structure. The three common types of support structures are shown in the following figure.

Figure 10 – Elevated Flare Support Structures (from API STD 521)

10.3.2 Offshore Facilities

Vertical or inclined flares can be either boom-supported or derrick supported.

10.4 Ground Flares

Ground flares are preferred if the flare discharge is to be kept out of the public view. An example of an enclosed ground flare is shown in the following figure.

Figure 11 – Enclosed Flare (from API STD 537)

10.5 Flare Gas Recovery Systems

Flare gas recovery is sometimes known as the “zero flare option.” The flare gas is recovered and returned for use as fuel gas or in the process itself. Typically, the system consists of one or more reciprocating compressors whose suction is connected to the flare header. A schematic for a flare-gas recovery system is shown in the following figure.

Figure 12 – Flare Gas Recovery System (from API STD 521)

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