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Flare and vent disposal systems

A flare or vent disposal system collects and discharges gas from atmospheric or pressurized process components to the atmosphere to safe locations for final release during normal operations and abnormal conditions (emergency relief). In vent systems, the gas exiting the system is dispersed in the atmosphere. Flare systems generally have a pilot or ignition device that ignites the gas exiting the system because the discharge may be either continuous or intermittent. Gas-disposal systems for tanks operating near atmospheric pressure are often called atmospheric vents or flares, and gas-disposal systems for pressure vessels are called pressure vents or flares. A flare or vent system from a pressurized source may include a control valve, collection piping, flashback protection, and a gas outlet. A scrubbing vessel should be provided to remove liquid hydrocarbons.

Possible components

A flare or vent system from an atmospheric source may include:

  • Pressure-vacuum valve
  • Collection piping
  • Flashback protection
  • Gas outlet

Hazard assessments

The actual configuration of the flare or vent system depends on the hazards assessment for the specific installation.

RP 520, Part 1, Sec. 8,[1] and RP 521, Secs. 4 and 5,[2] cover disposal and depressuring system design. RP 521, Appendix C, provides sample calculations for sizing a flare stack. RP 521, Appendix D[2], shows:

  • Flare-stack seal drum
  • Quench drum
  • Typical flare installation.

Knockout drums

RP 521, paragraph 5.4.2, provides detailed guidance for the design of knockout drums (also called relief drums or flare or vent scrubbers).[2] All flare, vent, and relief systems must include a liquid knockout drum. The knockout drum removes any liquid droplets that carry over with the gas relief sent to the flare. Most flares require that the particle size be reduced to a minimum of less than 300 μm. RP 14J suggests sizing for liquid droplets between 400 and 500 μm.[3] Most knockout drums are horizontal with a slenderness ratio (length-to-diameter ratio) between 2 and 4. A horizontal knockout drum must have a diameter large enough to keep the vapor velocity low enough to allow entrained liquids to settle or drop out.

Knockout drums operated at atmospheric pressure should be sized to handle the greatest liquid volume expected at the maximum rates of liquid buildup and pump out. RP 521 suggests 20 to 30 minutes of liquid holdup.[2] This is not practical in upstream operations. In onshore operations, it is recommended to take 20% of the maximum potential liquid stream and provide a 10-minute liquid holdup. For offshore operations, it is recommended to provide normal separation-retention times (1 to 3 minutes on the basis of API gravity) and an emergency dump design to handle the maximum liquid flow with no valves. An emergency sump (disposal) pile is recommended to dispose of the liquid, and a seal in the pile is recommended to contain the backpressure in the drum.

Knockout drums normally are operated at atmospheric pressure. To maintain an explosion, the MAWP of the knockout drum usually is set at 50 psig. Stoichiometric hydrocarbon/air explosions produce peak pressures seven to eight times the normal pressure.

Flashback protection

Flashback protection (the possibility that the flame will travel upstream into the system) should be considered for all disposal systems because flashback can result in pressure buildup in upstream piping and vessels. Flashback is more critical where there are tanks or pressure vessels with a MAWP less than 125 psig and in flare systems. RP 520 discusses flashback protection for pressure vents and flares,[1] and STD 2000 discusses atmospheric vents and flares.[4] RP 14C recommends that vents from atmospheric vessels contain a flame arrestor.[5] Because the flame arrestor can plug, a secondary pressure/vacuum valve without a flame arrestor should be considered for redundancy. The secondary system should be set at a pressure high enough and vacuum low enough so that it will not operate unless the flame arrestor on the primary system is plugged.

Pressure vents with vessels rated 125 psig and above normally do not need flashback protection. In natural-gas streams, the possibility of vent ignition followed by flash backpressures above 125 psig is minimal. When low-pressure vessels are connected to pressure vents, molecular or fluidic seals and purge gas often are used to prevent flashback. If relief valves are tied into the vent, the surge of flow when a relief valve opens could destroy a flame arrestor and lead to a hazardous condition. Also, there is a potential for flame arresters to become plugged. A means of flame snuffing should be considered for vent systems.

Flares have the added consideration of a flame always being present, even when there is a very low flow rate. They are typically equipped with molecular or fluidic seals and a small amount of purge gas to protect against flashback.

Seal drums

Knockout drums are sized with the gas-capacity equations referred to in the design of two- and three-phase separators in Oil and gas separators. Liquid seal drums are vessels that are used to separate the relief gases and the flare/header stack by a layer of liquid. Water (or water/glycol mixture) is normally the sealing fluid. The flare gas (or purge gas) is forced to bubble through a layer of water before it reaches the flare stack. This prevents air or gas from flowing backward beyond the water seal. Seal drums serve as a final knockout drum to separate liquid from the relief gases.

In a deep seal drum, the depth of the sealing fluid is designed to be equal to the staging pressure of the staged flare system. The sealing-fluid depth in most staging seal drums is typically in the range of 2 to 5 psig, which is equivalent to 5 to 12.5 ft of water column. In a shallow seal drum (conventional flashback prevention), the water seals have only a 6- to 10-in. water-column depth. It is important to design the deep seal drum with a proper gas velocity at the staging point to ensure that all the sealing fluid is displaced quickly at the staging pressure (an effect similar to a fast-acting valve actuator). It is also common to design the deep seal drum with a concentric overflow chamber to collect the displaced sealing fluid. The overflow chamber can be designed to flow back automatically into the sealing chamber once the gas velocity decreases below the rate required for closing off the second stage.

The depth of the liquid seal drum must be considered in calculating the relief-header backpressure. This depth is set by the flare supplier, but it usually can be altered somewhat, with the supplier’s concurrence, to suit plant conditions. Typical seal depths are 2 ft for elevated flares and 6 in. for ground flares. The height of the liquid seal can be determined by


where h = height of liquid seal, p = maximum allowable header backpressure, and ρ = sealing-liquid density.

The vessel-free area for gas flow above the liquid level should be a minimum of 3 ft or three times the inlet pipe cross-sectional area to prevent surges of gas flow to the flare and to provide space for disengagement.

RP 521 states that surging in seal drums can be minimized with the use of V-notches on the end of the dip leg. 6 If the water sloshes in the seal drum, it will cause pulsations in the gas flow to the flare, resulting in noise and light disturbances. Thus, most facilities prefer either a displacement seal or a perforated antislosh baffle. Fig. 1 shows seal-drum configurations.

Molecular seals

Molecular seals cause flow reversal. They normally are located below the flare tip and serve to prevent air entry into the stack. Molecular seals depend on the density difference between air and hydrocarbon gas. Light gas is trapped at the top of the U-tube. A continuous stream of purge gas is required for proper functioning of the gas seal, but the amount of purge gas is much less than would be required without the seal. The main advantages over liquid seals are that they do not slosh and they produce much less oily water. Gas seal must be drained, and the drain loop must be sealed. Because a gas seal with an elevated flare is required to keep air out of the flare stack, the liquid seal usually is omitted from an elevated-only flare system. If a vapor-recovery compressor is used, a liquid seal is used to provide a minimum header backpressure.

Fluidic seals

Fluidic seals are an alternative to gas seals. Fluidic seals use an open wall-less venturi, which permits flow out of the flare in one direction with very little resistance but strongly resists counterflow of air back into the stack. The venturi is a series of baffles, like open-ended cones in appearance, mounted with the flare tip. The main advantages of fluidic seals are that they are smaller, less expensive, and weigh less, and thus have less structural load on the flare stack, than molecular seals. However, fluidic seals require more purge gas than molecular seals.

Flame arrestors

Flame arrestors are used primarily on atmospheric vents and are not recommended on pressurized systems. Because of the acceleration of the flame, the flame arrestor must be installed approximately 10 pipe diameters from the exit, which prevents the flame from blowing through the arrestor. The length of the tube and surface area provided keep the metal cool. The major drawbacks of flame arrestors are that they are easily plugged, can become coated with liquid, and may not be strong enough for pressure-relief systems.

Flare Stacks

RP 521, Sec. 5.4.3, covers the design of elevated flares.[2] RP 521, Appendix C, provides examples of full design of a flare stack.[2] Most flares are designed to operate on an elevated flare stack or on angled booms on offshore platforms.

Elevated-flare-stack designs

Fig. 2 shows an example of an elevated-flare-stack design.

Self supported stacks

This is the simplest and most economical design for applications requiring short-stack heights (up to 100 ft overall height); however, as the flare height and/or wind loading increases, the diameter and wall thickness required become very large and expensive.

Guy wire supported stacks

This is the most economical design in the 100- to 350-ft height range. The design can be a single-diameter riser or a cantilevered design. Normally, sets of 3 wires are anchored 120 degrees apart at various elevations (1 to 6).

Derrick supported stacks

This is the most feasible design for stack heights above 350 ft. They use a single-diameter riser supported by a bolted framework of supports. Derrick supports can be fabricated from pipe (most common), angle iron, solid rods, or a combination of these materials. They sometimes are chosen over guy-wire-supported stacks when a limited footprint is desired.

Offshore flare support structures

Because offshore production platforms process very large quantities of high-pressure gas, the relief systems and, therefore, the flare systems, must be designed to handle extremely large quantities of gas quickly. By nature, flares normally have to be located very close to production equipment and platform personnel or located on remote platforms. Maximum emergency-flare design is based on emergency shut in of the production manifold and quick depressurization of the system. Maximum continuous-flare design is based on loss of produced-gas transport, single compression shutdown, gas-turbine shutdown, etc. Typical flare mountings on an offshore platform are angled boom mounting (most common), vertical towers, or remote flare platforms. Fig. 3 shows typical offshore flare-support structures.

Selection of the flare structure depends on such factors as:

  • Water depth
  • The distance between the flare and the production platform
  • Relief gas quantity
  • Toxicity
  • Allowable loading on the flare structure
  • Location of personnel
  • Location of drilling derrick
  • Locations of adjacent platforms
  • Whether the flaring is intermittent or continuous

Flare booms

Flare booms extend from the edge of the platform at an angle of 15 to 45° and are usually 100 to 200 ft long. Sometimes two booms oriented 180° from each other are used to take advantage of prevailing winds. Fig. 4 shows a diagram of an offshore flare boom.

Derrick supported flares

Derrick-supported flares (see Fig. 5) are the most common flare towers used offshore. They provide the minimum footprint (four-legged design) and dead load, which are critical design parameters for offshore flares and normally are used when space is limited and relief quantities moderate. Disadvantages of derrick-supported flares include possible crude-oil spill onto the platform, interference with helicopter landing, and higher radiation intensities.

Bridge supported flares

In the bridge-supported flare (see Fig. 6), the production platform is connected to a separate platform that is devoted to the flare structure. Bridges can be as much as 600 ft long, and bridge supports usually are spaced approximately every 350 ft.

Remote flares

Remote flares (see Fig. 7) are located on a separate platform connected to the main platform by a subsea relief line. The main disadvantage of remote flares is that any liquid carryover or subsea condensation will be trapped in pockets in the connecting line.

Flare stack design criteria

Important design criteria that determine the size and cost of flare stacks include flare-tip diameter and exit gas velocity, pressure-drop considerations, flare-stack height, gas dispersion limitations, flame distortion caused by lateral wind, and radiation considerations.

Flare tip diameter and exit gas velocity

The flare-tip diameter should provide a large enough exit velocity so that the flame lifts off the flare tip but not so large as to blowout the flare. The flare diameter and gas velocity normally are determined by the flare supplier. They are sized on the basis of gas velocity, although pressure drop should be checked.

Flare-Tip Diameter. Low-pressure flare tips are sized for 0.5 Mach for a peak, short-term, infrequent flow (emergency release) and 0.2 Mach for normal conditions, where Mach equals the ratio of vapor velocity to sonic velocity in that vapor at the same temperature and pressure and is dimensionless. These API 521 recommendations are conservative.[2] Some suppliers are designing "utility-type" tips for rates up to 0.8 Mach for emergency releases. For high-pressure flare tips, most manufacturers offer "sonic" flares that are very stable and clean burning; however, they do introduce a higher backpressure into the flare system. Smokeless flares should be sized for the conditions under which they are to operate smokelessly.

Velocity Determination. The sonic velocity of a gas can be calculated with


Gas velocity can be determined from


and the critical flow pressure at the end of the relief system can be calculated with



di = pipe inside diameter, in.;
k = ratio of specific heats, CP/CV;
PCL = critical pressure at flare tip, always ≥ 14.7, psia;
Qg = gas-flow rate, MMscf/D;
S = specific gravity, ratio;
T = temperature, °R;
V = gas velocity, ft/s;
VS = sonic velocity, ft/s;
Z = gas compressibility at standard conditions, where air = 1, psi −1 .

Pressure drop considerations

Pressure drops as large as 2 psi have been used satisfactorily. If the tip velocity is too small, it can cause heat and corrosion damage. Furthermore, the burning of the gases becomes quite slow and the flame is influenced greatly by the wind. The low-pressure area on the downwind side of the stack may cause the burning gases to be drawn down along the stack for 10 ft or more. Under these conditions, corrosive materials in the stack gases may attack the stack metal at an accelerated rate, even though the top 8 to 10 ft of the flare is usually made of corrosion-resistant material.

For conventional (open-pipe) flares, an estimate of the total flare pressure drop is 1.5 velocity heads, which is based on nominal flare-tip diameter. The pressure drop is determined by


where g = acceleration due to gravity, 32.3 ft/s2; V = gas velocity, ft/s; ΔPW = pressure drop at the tip, inches of water; and ρg = density of gas, lbm/ft3. Fig. 8 shows a "quick-look" nomograph to determine the flare-tip diameter.

Flare stack height

The height is generally based on the radiant-heat intensity generated by the flame. The stack should be located so that radiation releases from both emergency and long-term releases are acceptable and so that hydrocarbon and H2S dispersion is adequate if the flame is extinguished. The stack also should be structurally sound and withstand wind, earthquake, and other miscellaneous loadings. RP 521, Appendix C, provides guidance on sizing a flare stack.[2]

The Hajek and Ludwig equation (see RP 521) may be used to determine the minimum distance from a flare to an object whose exposure to thermal radiation must be limited.


D = minimum distance from the midpoint of the flame to the object being considered, ft;
E = fraction of heat radiated;
K = allowable radiation level, BTU/hr-ft2;
Q = heat release (lower heating value), BTU/hr; and
τ = fraction of heat intensity transmitted, defined by Eq. 7.

Table 1 shows component emissivity, and Table 2 shows allowable radiation levels. Humidity reduces the emissivity values in Table 1 by a factor of τ, which is defined by



r = relative humidity, fraction;
R = distance from flare center, ft;
τ = fraction of heat transmitted, in range of 0.7 to 0.9.

Gas dispersion limitations

In some cases, it may be desirable to check the stack height on the basis of atmospheric dispersion of pollutants. Where this is required, the authorities with jurisdiction normally will have a preferred calculation method.

Flame distortion caused by lateral wind

Another factor to be considered is the effect of wind tilting the flame, which varies the distance from the center of the flame. The center of the flame is considered to be the origin of the total radiant-heat release with respect to the plant location under consideration. API RP 521[2] gives a generalized curve for approximating the effect of wind.

Radiation considerations

There are many parameters that affect the amount of radiation given off by a flare including the type of flare tip, whether sonic or subsonic (HP or LP) or assisted or nonassisted; emissivity of flame produced or flame length produced; amount of gas flow; heating value of gas; exit velocity of flare gas; orientation of flare tip; wind velocity; and humidity level in air.

Several design methods are used for radiation calculations. The most common methods are the API simple method and the Bruztowski and Sommers method. Both methods are listed in RP 521, Appendix C.[2] These methods are reasonably accurate for simple low-pressure pipe flares (utility flare) but do not accurately model high-efficiency sonic-flare tips, which produce short, stiff flames. The fourth edition of RP 521 suggests that manufacturers’ proprietary calculations should be used for high-efficiency sonic-flare tips.[2]

Purge gas

Purge gas is injected into the relief header at the upstream end and at the major branches to maintain a hydrocarbon-rich atmosphere in each branch, into the off-plot relief system, and into the flare stack. The gas volume typically is enough to maintain the following velocities: ft/s for density seals, 0.4 ft/s for fluidic seals, and 0.4 to 3 ft/s for open-ended flares. RP 521 states that the oxygen concentration must not be greater than 6% at 25 ft inside the tip.[2] When there is enough PSV leakage or process venting to maintain the desired backpressure, no purge gas is injected.

Burn pits

Burn pits can handle volatile liquids. They must be large enough to contain the maximum emergency flame length and must have a drain valve and pump (if required) to dispose of trapped water. The flare should be pointed down, and the pilot should be reliable. Because of the uncertainty regarding the effects of wind on the center of the flame, it is recommended that the greater of either 50 ft or 25% be added to the calculated required distance behind the tip. Burn pits should be at least 200 ft from property lines. A fence or some other positive means for keeping animals and personnel away from a potential radiation of 1,200 BTU/hr-ft2 should be installed.

Vent design

The size of a vent stack must consider radiation, velocity, and dispersion.


The vent should be located so that radiation levels from ignition are acceptable.


The vent must have sufficient velocity to mix air with gas to maintain the mixed concentration below the flammable limit within the jet-dominated portion of the release. The vent should be sized for an exit velocity of at least 500 ft/s (100 ft/s minimum). Studies indicate that gases with velocities of 500 ft/s or more have sufficient energy in the jet to cause turbulent mixing with air and will disburse gas in accordance with the following equation.



W = weight flow rate of the vapor/air mixture at distance Y from the end of the tailpipe;
Wo = weight flow rate of the relief-device discharge, in the same units as W ;
Y = distance along the tailpipe axis at which W is calculated;
Dt = tailpipe diameter, in the same units as Y.

Eq. 8 indicates that the distance Y from the exit point at which typical hydrocarbon relief streams are diluted to their lower flammable limit occurs approximately 120 diameters from the end of the discharge pipe. As long as a jet is formed, there is no fear of large clouds of flammable gases existing below the level of the stack. The distance to the lean flammability concentration limits can be determined from API RP 521[2] and API RP 14C.[5] The horizontal limit is approximately 30 times the tailpipe diameter.

Industry practice is to locate vent stacks 50 ft horizontally from any structure running to a higher elevation than the discharge point. The stacks must vent at least 10 ft above any equipment or structure within 25 to 50 ft above a potential ignition source. Because the flame can be ignited, the height of the stack must be designed or the pit located so that the radiation levels do not violate emergency conditions.


The vent must be located so that dispersion is adequate to avoid potential ignition sources. The dispersion calculation of low-velocity vents is much more difficult and should be modeled by experts familiar with the latest computer programs. Location of these vents is very critical if the gas contains H2S because even low concentrations at levels accessible by personnel could be hazardous. The location of low-velocity vents should be checked for radiation in the event of accidental ignition.


Cp/CV = specific heats at constant pressure and temperature, dimensionless
d = nominal tip diameter, L, in.
di = pipe inside diameter, L, in.
D = minimum distance from the midpoint of the flame to the object being considered, L, ft
Dt = tailpipe diameter, L, in the same units as Y
E = fraction of heat radiated
g = acceleration due to gravity, 32.3 ft/sec2
h = height of liquid seal, L, ft
k = ratio of specific heats, CP/CV
K = allowable radiation level, BTU/hr-ft2
L = flame length, L, ft
p = maximum allowable header backpressure, m/Lt2, psi
PCL = critical pressure at flare tip, m/Lt2, psia
Q = heat release (lower heating value), BTU/hr
Qg = gas-flow rate, MMscf/D
r = relative humidity, fraction
R = distance from flare center
S = specific gravity, fraction
t = temperature, T, °F
T = temperature, T, °R
Ux = lateral-wind velocity, L
Uj = exit gas velocity from stack, L
V = gas velocity, L/t, ft/sec
VS = sonic velocity, L/t, ft/sec
W = weight flow rate of the vapor/air mixture at distance Y from the end of the tailpipe, mL/t
Wf = gas-flow rate, lbm/hr
Wo = weight flow rate of the relief device discharge in the same units as W, mL/t
xc = horizontal distance from flare tip to flame center, L
yc = vertical distance from flare tip to flame center, L
Y = distance along the tailpipe axis at which W is calculated, L
Z = gas compressibility at standard conditions, Lt2/m, psi−1
ΔPW = pressure drop at the tip in inches of water
Δx = horizontal flame distortion caused by lateral wind, L, ft
Δy = vertical flame distortion caused by lateral wind, L, ft
ρ = sealing-liquid density, lbm/ft3
ρg = density of gas, lbm/ft3
τ = fraction of heat intensity transmitted


  1. 1.0 1.1 API RP 520, Design and Installation of Pressure Relieving Systems in Refineries, Part I, seventh edition. 2000. Washington, DC: API.
  2. 2.00 2.01 2.02 2.03 2.04 2.05 2.06 2.07 2.08 2.09 2.10 2.11 2.12 API RP 521, Guide for Pressure-Relieving and Depressuring Systems, fourth edition. 1999. Washington, DC: API.
  3. API RP 14J, Design and Hazards Analysis for Offshore Production Facilities. 1993. Washington, DC: API.
  4. API STD 2000, Venting Atmosphere and Low-Pressure Storage Tanks—Nonrefrigerated and Refrigerated, fifth edition. 1999. Washington, DC: API.
  5. 5.0 5.1 API RP 14C, Analysis Design, Installation and Testing of Basic Surface Safety Systems for Offshore Production Platforms. 1998. Washington, DC: API.

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External links

API Standards

See also

Safety systems

Recommended methods for safety analysis

Relief valves and relief systems