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Eni S.p.A. Exploration & Production Division

BEST PRACTICE

UNIT 230

RELIEF AND BLOWDOWN SYSTEM

10004.HTP.PRC.PRG

Rev. 0 January 2008

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10004.HTP.PRC.PRGRev. 0 January 2008

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INDEX

ACRONYMS 5

RELIEF AND BLOWDOWN SYSTEM UNIT 230 6

1.1 General ..................................................................................................................................6 1.2 Systems Description .............................................................................................................. 6 1.3 Relief System Design............................................................................................................. 7

1.3.1 Overpressure Protection Philosophy ........................................................................7 1.3.2 Upset Conditions.......................................................................................................8

1.3.2.1 Blocked Discharge..................................................................................... 8 1.3.2.2 Inadvertent Valve Opening ........................................................................9 1.3.2.3 Control Valve Failure ................................................................................. 9 1.3.2.4 Utility Failure .............................................................................................. 9 1.3.2.5 Fire Exposure .......................................................................................... 10 1.3.2.6 Jet Fire ..................................................................................................... 10 1.3.2.7 Entrance of volatile material into the system........................................... 11 1.3.2.8 Thermal Expansion..................................................................................11 1.3.2.9 Tube Rupture........................................................................................... 11 1.3.2.10 Internal Explosion ....................................................................................12 1.3.2.11 Chemical Reaction...................................................................................12 1.3.2.12 Hydraulic Expansion................................................................................ 12

1.3.3 Additional Consideration .........................................................................................14 1.3.3.1 Pumps......................................................................................................14 1.3.3.2 Compressors ........................................................................................... 15 1.3.3.3 Turbines................................................................................................... 15 1.3.3.4 Fired Heaters ........................................................................................... 15 1.3.3.5 PSV Operating in Liquid Service ............................................................. 15 1.3.3.6 Atmospheric and Low Pressure Storage Tanks ...................................... 18

1.3.4 Relief Devices .........................................................................................................18 1.3.4.1 Spring loaded relief valves....................................................................... 18 1.3.4.2 Pilot-operated relief valves ......................................................................19 1.3.4.3 Rupture disks........................................................................................... 20

1.3.5 Relief Valves Location.............................................................................................20 1.3.6 Piping Upstream of a Relief Device ........................................................................21

1.4 Blowdown System Design ................................................................................................... 23 1.4.1 Determination of Blowdown Requirements............................................................. 24 1.4.2 Sectioning of the Process Systems ........................................................................26 1.4.3 Depressuring Device Location ................................................................................27

1.5 Layout of Downstream Piping Systems ...............................................................................28 1.5.1 Common Discharge Systems..................................................................................28 1.5.2 Blockage Due to Hydrate Formation in Downstream Piping System......................29

1.6 Isolation Valves in Pressure Relief Piping ...........................................................................29 1.6.1 Isolation Valves Requirements................................................................................30 1.6.2 Interlocking Systems ............................................................................................... 33

1.6.2.1 Discharge to Atmosphere ........................................................................34 1.6.2.2 Discharge to Closed System ...................................................................34

1.7 Disposal System .................................................................................................................. 36 1.7.1 General....................................................................................................................36 1.7.2

Atmospheric discharge............................................................................................37

1.7.3 Disposal by Flaring..................................................................................................37 1.7.4 Flaring Versus Venting............................................................................................37

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1.7.5 Flare and Vent Structure.........................................................................................39 1.7.5.1 Self-supported ......................................................................................... 39 1.7.5.2 Guy-wire supported .................................................................................40 1.7.5.3 Derrick supported ....................................................................................40

1.8

Flare System Design............................................................................................................40 1.8.1 Flare Type ...............................................................................................................41

1.8.1.1 Exothermic Flares.................................................................................... 41 1.8.1.2 Endothermic Flares..................................................................................43 1.8.1.3 Enclosed Ground Flares..........................................................................44

1.8.2 Flare Sizing .............................................................................................................45 1.8.2.1 Evaluation of Flare Diameter ...................................................................45 1.8.2.2 Evaluation of Flare Height .......................................................................45

1.8.3 Segregated flare systems .......................................................................................46 1.8.4 Flare Disposal of Hydrogen Sulphide .....................................................................47

1.9 Other Flaring Equipment......................................................................................................48 1.9.1 K.O. Drum ...............................................................................................................48

1.9.1.1 K.O. Drum Pump and Instrumentation ....................................................49 1.9.1.2 K.O. Drum Sizing .....................................................................................49

1.9.2 Liquid Seals.............................................................................................................51 1.9.3 Purge System..........................................................................................................51

1.10 Vent System Design ............................................................................................................ 52 1.10.1 Vent Sizing ..............................................................................................................52 1.10.2 Individual vent outlets..............................................................................................53

1.11 Flare Radiation Study .......................................................................................................... 54 1.12 Relief and Blowdown System Highlights .............................................................................61

APPENDIX 1 - SIZING OF RELIEF DEVICES ..............................................................................65 Design Considerations ............................................................................................ 65 Sizing for Gas or Vapour Relief...............................................................................67 Sizing for Steam Relief............................................................................................ 71 Sizing for Liquid Relief ............................................................................................ 72 Sizing for Two Phase Liquid-Vapour Relief ............................................................ 74 Sizing for Thermal Relief......................................................................................... 74

APPENDIX 2 HIGH INTEGRITY PROTECTION SYSTEM (HIPS) ............................................ 76 Reference Documents ............................................................................................ 76 HIPS Justification.................................................................................................... 78 HIPS Design............................................................................................................79

Advantages and Disadvantages of HIPS................................................................ 84 GLOSSARY 87

REFERENCE 92

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For Main Utilities Best Practice reference shall be made to Eni E&P

internal document No. 10002.HTP.PRC.PRG .

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ACRONYMS

BDV Blowdown valve

CCF Common cause failure

DIERS Design institute for emergency relief system

ESD Emergency shutdown

HIPS High integrity protection system

LHV Lower heating value

PES Programmable electronic system

PRV Pressure relief valve

PSV Pressure safety valve

SIL Safety integrity level

SIS Safety instrumented system

SRS Safety requirement specification

S/R VALVE Safety / Relief valve

TSV Thermal safety valve

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RELIEF AND BLOWDOWN SYSTEM UNIT 230

1.1 General

This document sets out the general guidelines for sizing and designing a

relief and blowdown system, for both on-shore and off-shore production

facilities, with particular attention to the flare sizing.

The principal elements of pressure relief systems are the individual

pressure relief devices, the flare piping system, the flare separator drum,

and the flare including sealing devices, purge and steam injection for

smokeless burning.

Design of relief systems must comply with applicable state and federal

codes and laws as well as the requirements of the insurance covering the

plant or installation. State and federal regulations not only cover safety

but also environmental considerations such as air and water pollution and

noise abatement.

This section presents a convenient summary of relief, depressuring and

disposal systems information obtained from API 520 / 521 / 526 / 537 and

other sources.

1.2 Systems Descr ipt ion

Pressure relieving devices have to be installed to ensure that a process

system or any of its components are not subjected to pressures that

exceed the design pressure. API 521 recommends a depressurization

time (to 7 barg) of 15 minutes (see Paragraph 1.4) ; therefore, relieving

flowrates can be considered to be continuous rates of limited duration 10

- 15 min. The relieving rate will cease once the source of overpressure is

isolated.

Blow-down depressuring valves are intended to provide for a rapid

reduction of pressure in equipment by releasing vapours, as pressure

safety valves cannot provide depressuring and merely limit the pressure

rise under emergency conditions.

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1.3 Relief System Design

The flowrates to the system can be caused by various operating and

upset conditions not all of which are of emergency type.

Even though the determination of relieving rates for each upset condition

and sizing of the relevant relief device is out of the scope of the work, in

the following is given a brief description of the most common

overpressure causes; moreover, Appendix 1 contains some relief devices

sizing methods. However, for a more rigorous determination of individual

relieving rates and relief devices sizing reference should be made

respectively to Section 5 of API 521 and to API 520.

1.3.1 Overpressure Protection Philosophy

Overpressure is due to a deviation of the normal operating conditions and

it is the result of an unbalance or disruption of the normal flows of

material and energy that causes the material or energy, or both, to build

up in some part of the system. Analysis of the causes and magnitudes of

overpressure is, therefore, a special and complex study of material and

energy balances in a process system.

Overpressure may result from:

(a) heat input, which is indirect pressure input through vaporization

or thermal expansion

(b) direct pressure input from higher pressure sources.

The causes of overpressure are considered to be unrelated if no process

or mechanical or electrical linkages exist among them, or if the length of

time that elapses between possible successive occurrences of these

causes is sufficient to make their classification unrelated.

The simultaneous occurrence of two or more unrelated causes of

overpressure (also known as double or multiple jeopardy) is not a basis

for design. Example double jeopardy scenarios might be: fire exposure

simultaneous with exchanger internal tube failure, fire exposure

simultaneous with failure of administrative controls to drain and

depressure isolated equipment, or operator error that leads to a blocked

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outlet coincidental with a power failure. On the other hand, instrument air

failure during fire exposure may be considered single jeopardy if the fire

exposure causes local air line failures.

1.3.2 Upset Conditions

Pressure vessels, heat exchangers, operating equipment, and piping are

designed to contain the system pressure. The equipment design is based

on the normal operating pressure at operating temperatures, the effect of

any combination of process upsets that are likely to occur and the

differential between the operating and set pressures of the pressure-

relieving device.

The process systems designer must define the minimum pressure relief

capacity required to prevent the pressure in any piece of equipment from

exceeding the maximum allowable accumulated pressure.

In the following is given a brief description of some common occurrences

that may require overpressure protection. This summary is not intended

to be all inclusive; it is merely recommended as a guide.

1.3.2.1 Blocked Discharge

The inadvertent closure of a block valve on the outlet of a pressure

vessel while the plant is on stream may expose the vessel to a pressure

that exceeds the maximum allowable working pressure.

If closure of an outlet block valve can result in overpressure, a pressure

relief device is required unless administrative procedures to control valveclosure, such as car seals or locks, are in place. In this case, the relief

load is usually the maximum flow which the pump, compressor, or other

flow source produces at relief conditions. The quantity of material to be

relieved should be determined at conditions that correspond to the set

pressure plus overpressure instead of at normal operating conditions.

Instantaneously, the flowrate to be discharged should be higher than the

normal operating flow (e.g. compressor). Moreover, the presence of a

liquid outlet on the vessel (LV) could decrease the flowrate to be

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discharged. However, during design operation the worst case shall be

considered; therefore, only the higher flowrate case (absence of liquid

outlet or closed LV) shall be deeply analyzed for relief device sizing.

1.3.2.2 Inadvertent Valve Opening

The inadvertent opening of any valve from a source of higher pressure,

such as high-pressure steam or process fluids, should be considered.

This action may require pressure-relieving capacity unless provisions are

made for locking or sealing the valve closed.

This overpressure scenario can be due to operator error, who can

operate the valve in the wrong position, or to valve leakage. In these

cases, the relief valve shall be sized considering the maximum valve C v

declared by the manufacturer and the maximum p across the valve

(valve set pressure protected equipment design pressure).

1.3.2.3 Control Valve Failure

The failure positions of instruments and control valves must be carefullyevaluated. A valve may stick in the wrong position, or a control loop may

fail. If one or more of the inlet valves are opened by the same failure that

caused the outlet valve to close, pressure-relieving devices may be

required to prevent overpressure. The required relief capacity is the

difference between the maximum inlet and maximum outlet flows.

1.3.2.4 Utility Failure

The consequences that may develop from any utility service loss,

whether local or plantwide, must be carefully evaluated. The normal utility

services that could fail and a partial listing of affected equipment that

could cause overpressure are given in Table 1.3.1.

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Utility Failure Equipment Affected

Pumps for cooling water circulation or any other service such as boiler feed, reflux, etc.

Air cooler fans, cooling tower

Compressors (for air, vacuum, refrigeration, etc.)Instrumentation

Electric

Motor-operated valvesCondensers and coolersCooling Water Jackets on rotating equipmentTransmitters / Controllers / AlarmsInstrument Air Regulating valvesTurbine driversReboilersReciprocating pumps

Steam

Direct steam injection equipmentBoilers

Engine driversCompressorsFuelGas TurbinesSealsInert Gas Purge System

Table 1.3.1 Possible utility failure and relevant equipment affected.

1.3.2.5 Fire Exposure

Even if fire is not usually the condition that may create the greatest

relieving requirements, it is the most common case.

Various empirical equations have been developed to determine relief

loads from vessels exposed to fire. Formula selection varies with the

system and fluid considered (see API 521, Section 5).

1.3.2.6 Jet Fire

Jet fire is a fire created when a leak from a pressurized system ignites

and forms a burning jet. Jet fires can occur when almost any combustible

/ flammable fluid under pressure is released to atmosphere. Equipment

failure during a jet-fire is due to a localized and instantaneous

overheating without a significant pressure increase in the equipment (the

relief device set point isnt often reached). This is due to the localized

nature of heating whereby the bulk fluid temperature might not increase

appreciably. Hence, a relief device might not prevent vessel failure from

jet fire impingement.

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Instead of a pressure-relief system, protection against jet fires focuses on

prevention of leaks through proper maintenance and/or mitigation

systems such as fireproofing, depressuring systems, isolation of leaks,

equipment and/or flange orientation and minimization and emergency

response.

1.3.2.7 Entrance of volatile material into the system

Entrance of water or light hydrocarbons into hot oil, causing a great and

instantaneous expansion in volume, can cause system overpressure.

Normally, a pressure relieving device is not provided for this contingency.

Proper design and operation of the process system are essential in

attempts to eliminate this possibility.

1.3.2.8 Thermal Expansion

If isolation of a process line on the cold side of an exchanger can result in

excess pressure due to heat input from the warm side, then the line or

cold side of the exchanger should be protected by a pressure safetyvalve (PSV). If any equipment, item or line can be isolated while full of

liquid, a PSV should be provided for thermal expansion of the contained

liquid.

1.3.2.9 Tube Rupture

When a large difference exists between the design pressure of the shell

and tube sides of an exchanger, provisions is required for relieving the

low pressure side (it could be required either on shell side or on tube

side). Because the test pressure is normally about 150% of the design

pressure, a 2/3 rule is established from it. The rule is this: pressure relief

for tube rupture is not required where the low pressure exchanger side

(including upstream and downstream systems) is designed at or above

the 2/3 criteria. Because ASME changed the hydrostatic test pressure for

pressure vessels from the 150% design pressure to a new standard of 130% design pressure, the existing 2/3 rule changed to a 10/13 rule.

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As a general rule, the required relief capacity is based on twice the tube

cross section area, and the assumption that high pressure fluid can flow

through both the tube stub and the other end of the tube.

1.3.2.10 Internal Explosion

Where overpressure protection against internal explosions (excluding

detonation) caused by ignition of vapour-air mixtures is to be provided,

rupture discs or explosion vent panels, not relief valves, should be used.

Relief valves cannot be used in this case because they react too slowly to

protect the vessel against the extremely rapid pressure build-up caused

by internal flame propagation.

1.3.2.11 Chemical Reaction

The rapid evolution of an exothermic reaction (runaway) or the

degradation reaction which generates gas products can cause the vessel

rupture. Exothermic reactions become dangerous only when the

produced heat is greater than the removed heat and the temperatureincrease causes a reaction rate increase.

Protection against reaction runaway or gases generation should be

provided. The methodology for determining the appropriate size of an

emergency vent system for chemical reactions was established by DIERS

(Design Institute for Emergency Relief Systems).

1.3.2.12 Hydraulic Expansion

Hydraulic expansion is the increase in liquid volume caused by an

increase in temperature. It can result from:

(a) Piping or vessels are blocked-in while they are filled with cold

liquid and are subsequently heated.

(b) An exchanger is blocked-in on the cold side with flow in the hot

side.

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(c) Piping or vessels are blocked-in while they are filled with liquid at

near-ambient temperatures and are heated by direct solar

radiation.

Provisions are required for relieving the equipment. The capacity

requirement is not easy to determine. Since every application will be

relieving liquid, the required capacity of the thermal safety valve (TSV)

will be small; specifying an oversized device is, therefore, reasonable. A

3 4 1 nominal pipe size (NPS 3 4 NPS 1) relief valve is commonly

used.

Proper selection of the set pressure for these relieving devices should

include a study of the design rating of all items included in the blocked-insystem. The TSV pressure setting should never be above the maximum

pressure permitted by the weakest component in the system being

protected.

3 4 1 size is not adequate for long pipelines of large diameter in

uninsulated aboveground installations and large vessels or exchangers

operating liquid-full; in these cases, in order to evaluate the relief device

proper size, the following equation must be applied:

cdq V

=

1000

(1)

Where:

q volume flowrate at flowing temperature [m/s]

V cubic expansion coefficient for the liquid at the expected

temperature [1/C]

total heat transfer rate [W]

d relative density referred to water ( d = 1.00 @15.6C)

c specific heat capacity of trapped fluid [J/kgK]

For aboveground pipelines protection, a system with multiple TSVs shall

be provided. The distance from one TSV to the other is specified on

mechanical standard documents.

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If the liquid being relieved is expected to flash or form solids while it

passes through the relieving device, the procedure described in API 520

is recommended.

1.3.3 Additional Consideration

In the following is given a short summary for sizing the relief devices for

those equipment, such as pumps, compressors, atmospheric and low

pressure storage tanks, etc., which are not included in the API 520 and

API 521. This paragraph is also intended to give a brief description about

pressure safety valve operating in liquid service.

1.3.3.1 Pumps

Alternative pumps, in order to avoid the motor pump overheating and to

protect the piping downstream from pressures greater than design

pressure, require a safety valve on the discharge. Therefore, because of

the double function of the relief valve (protection against overpressure

and overheating), this devices shall be sized for both overpressure andoverheating. For overheating considerations, the pump manufacturer

shall be consulted.

Normally, these devices are piped back to the vessel or piping upstream

of the pump rather than to the flare system.

For a preliminary estimation of the valve set pressure, the following

equation shall be applied. The valve set pressure is calculated using both

equations; the chosen value is the greater between the two results.

deliveryset pp = 1.1 (2)

deliveryset pp += 7.1 (3)

Where:

pset Valve set pressure [bar]pdelivery Pump delivery pressure [bar]

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For valves sizing a flowrate value equal to the pump flowrate (or pump

maximum flowrate in case of pumps with variable motor) must be taken

into consideration.

Lines and equipment downstream a centrifugal pump have always a

design pressure equal to the pump shut-off pressure. Wherever this rule

is not applied, the piping and / or equipment downstream the pump shall

be protected with a relief device.

1.3.3.2 Compressors

In order to protect rotary compressors and lines, a relief valve upstream

of the block and check valves shall be provided on the compressor

delivery and, if foreseen, on each of the intermediate stages.

1.3.3.3 Turbines

A special pressure relief valve shall be foreseen at the turbine outlet in

order to prevent overpressure phenomena at the condenser in case of cooling water loss or other system failure.

This kind of valve, without spring, acts against atmospheric back-

pressure and requires water for seals.

1.3.3.4 Fired Heaters

If there is a possibility that the process side of a fired heater may be

blocked-in, then a relief valve should be provided to protect the heater.

1.3.3.5 PSV Operating in Liquid Service

For those relief valves protecting equipment operating in liquid service,

the set pressure shall be evaluated taking into consideration the liquid

head and the elevation of the valve itself.

During the first engineering phase, the valve elevation could be uncertain;

in these cases, the designer shall evaluate the valve set pressure

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supposing a reasonable valve height. For valve elevation preliminary

estimate the following method shall be applied:

a) Considering a relief header laying on the pipe-rack at an

elevation of 10 m and equipment with an upper tangent line lower

than 10.5 m, the safety valve set pressure shall be evaluated

supposing a PSV elevation of at least 10.5 m aboveground.

Figure 1.3.1 PSV in l iquid serv ice.

b) For all the equipments whose upper tangent line is higher than10.5 m (or above the relief header upper tangent line), the

following considerations shall be applied:

b.1) If the equipment is inside a structure, the PSV shall be

positioned 1.5 m above the first level over the equipment upper

tangent line. This level is 3 m above the upper tangent line.

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Figure 1.3.2 - PSV in liquid service.

b.2) If there isnt a level over the equipment, the PSV shall have a

minimum elevation above the upper tangent line.

Figure 1.3.3 - PSV in liquid service.

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1.3.3.6 Atmospheric and Low Pressure Storage Tanks

In this paragraph is given a short description of relief devices required for

storage tanks designed for operation at pressure from vacuum to 15 psig

(103.4 kPag) overpressure protection. For more rigorous information

about atmospheric and low pressure overpressure protection, reference

shall be made to API 2000.

Common overpressure causes for this kind of storage tank (with or

without weak roof-to-shell attachment) are listed in the following:

Liquid movement into or out of the tank;

Tank breathing due to weather changes;

Fire exposure

Other circumstances such as equipment failure or operating

errors.

In case of tanks with fixed roof, the PSV to be installed shall be sized

considering the most severe overpressure condition.

Tanks with weak roof-to-shell attachment, as better specified in API 650,

are designed with a roof-to-shell connection which fails in case of fire and

protect the equipment itself. Hence, for a tank built to these

specifications, a relief device for protecting the equipment exposed to fire

is not required. However, an overpressure protection for the most severe

condition identified among the remaining overpressure causes is

required. The PSV to be installed shall be sized for the most severe

condition and assuming the blanketing valve fully opened.

1.3.4 Relief Devices

1.3.4.1 Spring loaded relief valves

A conventional pressure relief valve is a self-actuated spring-loaded

pressure relief valve which is designed to open at a predetermined

pressure and protect a vessel or system from excess pressure by

removing or relieving fluid from that vessel or system.

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Conventional spring-loaded relief valves shall be installed where back-

pressure does not exceed 10% of the set pressure (see API 520, Section

3, Paragraph 3.3.3.1)

A balanced pressure relief valve is a spring loaded pressure relief valve

which incorporates a bellows or other means of balancing the valve disc

to minimize the effects of back pressure on the performance

characteristics of the valve.

Balanced pressure relief valves should be considered where the built-up

back pressure (back pressure caused by flow through the downstream

piping after the relief valve lifts) is too high for a conventional pressure

relief (see API 520, Section 3, Paragraph 3.3.3.1).In general, balanced pressure relief valves are suitable for back-

pressures ranging from 10% to 50% of the set pressure. They can be of

two main types: balanced piston and balanced bellows. Balanced bellows

shall be given preference where the fluid is corrosive or fouling.

1.3.4.2 Pilot-operated relief valves

A pilot-operated pressure relief valve consists of the main valve, which

normally encloses a floating unbalanced piston assembly, and an

external pilot.

Pilot-operated relief valves shall be selected rather than conventional

spring-loaded relief valves when any of the requirements listed

hereinafter is present: low accumulation rates, calibration without

removing the valve, handling of large flows, higher pressure in the

downstream piping is required etc.

It shall be ensured, before selecting a pilot-operated relief valve, that

there is no possibility of blockage of the pilot valve or sensing line due to

hydrates, ice, wax or solids. There shall be no low points in the sensing

line or its take off, and all fine bore elements exposed to process fluids

shall be heat-traced and insulated if non-blockage cannot be guaranteed.

Filters shall not be used in the sensing line to the pilot valve because they

can increase the risk of blockage.

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1.3.4.3 Rupture disks

Rupture disk devices are non-reclosing pressure relief devices used to

protect vessels, piping and other pressure containing components from

excessive pressure and/or vacuum. Rupture disks are used in single and

multiple relief device installations. They are also used as redundant

pressure relief devices.

With no moving parts, rupture disks are simple, reliable and faster acting

than other pressure relief devices. Because of these, rupture disks are

used in any application requiring overpressure protection where a non-

reclosing device is suitable.

Moreover, because of their light weight, rupture disks can be made from

high alloy and corrosion-resistant materials that are not practical in

pressure relief valves.

These devices can be specified for systems with vapour or liquid

pressure relief requirements. Also, rupture disk designs are available for

highly viscous fluids. The use of rupture disk devices in liquid service

should be carefully evaluated to ensure that the design of the disk is

suitable for liquid service. The user should consult the manufacturer for

information regarding liquid service applications.

Rupture disks can be of various types; for more details see API 520.

1.3.5 Relief Valves Location

To ensure protection of the whole system, the relief assembly should be

located, where practical, in the upstream part, i.e. where the highest

pressure occurs, and as close as possible to the source of overpressure.

Relief valves shall be connected to the protected equipment in the vapour

space above any contained liquid or to piping connected to the vapour

space. An exception can be made if the vessel is fitted with a demister

mat. In this case the relief connection shall be upstream of the mat,

unless the relieving capacity is of the same order of magnitude as the

normal operating flow through the demister mat.

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The pressure drop of the piping between protected equipment and its

relief valve shall not exceed 3% of the set pressure.

The inlet and outlet piping shall be installed without pockets to ensure

that liquid does not accumulate at the relief valve outlet or inlet.

Relief valves discharging to atmosphere should be located at the

maximum practical elevation to keep discharge piping (to safe location)

as short as possible. In case of multiple relief valves (including one

spare), each relief valve shall have an individual discharge pipe (see also

API 521).

Relief valves connected to a closed relief system shall be located above

the relief header. Relief valve outlet lines should be connected to the topof the header, or at least so that the header cannot drain back into outlet

lines even with the header full of liquid. If the valves cannot be put above

the header, they shall be lined up to discharge into a local drain vessel.

Alternatively, if the problem of elevation is confined to a few valves, outlet

lines to the header shall be heat-traced from the relief valve to the highest

point of the line. Heat tracing isnt permitted for relief valves which

discharge a medium which can leave a deposit.Relief valve systems require periodic inspection and maintenance and

hence they should be easily accessible.

1.3.6 Piping Upstream of a Relief Device

In order to ensure safe disposal of flared and vented streams, certain

factors shall be taken into consideration when designing the pipework

upstream of the relief device.Piping upstream of a relief device should be designed with as few

restrictions to flow as possible and should not be pocketed.

The flow area through all pipe and fittings between a pressure vessel and

its relief valve shall be at least the same as that of the valve inlet (e.g.

isolation valves shall be full bore).

Depending on the actual relief valve capacity, the pressure drop of the

inlet piping and fittings shall not exceed 3% of the valve set pressure (thisis to avoid chatter, which will result in significant seat damage and loss of

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capacity). Exceptions to this requirement are only allowed in the case of a

pilot-operated valve with a suitably arranged remote pilot connection

close to the source of overpressure.

The above is especially applicable to relief valves handling gas or vapour.

Relief valves in pure liquid service require special attention, since in this

case chatter may also be caused by the acceleration of the (non

expandable) liquid in the inlet piping: a change in pressure amounting to

more than 3% of the set pressure will readily occur and cause valve

chatter. In this case the likelihood of chatter can be limited by installing a

relief valve with a special liquid trim (linear flow characteristic) thereby

avoiding the need to take the relief valve capacity to determine thepressure drop of the inlet piping. For PSV sizing in liquid service see

paragraph 1.3.3.5.

When two or more relief valves (spares not counted) are fitted on one

connection, the cross-sectional area of this connection shall be at least

equal to the combined inlet areas of the valves, and the above pressure

drop requirement shall apply for the combined flow of the valves.

Relief valves on cold process streams shall have an uninsulated inlet lineof sufficient length to prevent icing of the relief valve, in particular the disk

and spring. Alternatively, heat tracing may be required. Special attention

shall be paid in this respect to valves which discharge into the

atmosphere, i.e. in those having open outlets which may become blocked

with ice.

To avoid the need for special high temperature materials, relief valves on

hot process streams may be installed using an uninsulated length of inletline, creating a cold dead ended leg between the process stream and the

relief valve.

A pressure safety valve typical scheme is shown in Figure 1.3.4.

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Figure 1.3.4 PSV typical s cheme.

1.4 Blowdown System Design

Because of a relief valve cannot depressurize a system but can only limit

the pressure rise to the set point during upset conditions, a dedicated

depressuring system is required to mitigate the consequences of a vessel

leak by reducing the leakage rate or to reduce the failure potential for

scenarios involving overheating (e.g. fire).

When metal temperature is increased due to fire or exothermic or

runaway process reactions, the metal temperature may reach a level at

which stress rupture could occur. This may be possible even though the

system pressure does not exceed the maximum allowable accumulation.

In this case, depressuring reduces the internal stress thereby extending

the life of the vessel at a given temperature.

In order to be effective, the depressuring system must depressure the

vessel such that the reduced internal pressure keeps the stresses below

the rupture stress. API 521 suggests depressurizing to 6.9 barg or 50% of

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vessel design pressure, whichever is the lower, within 15 minutes.

Moreover, Eni E&P internal standard, see doc. no. 20199.VON.SAF.SDS,

suggests reaching the 50% of vessel operating pressure within 5 minutes

and then depressurizing to 7 barg within the next 10 minutes. Even

though API 521 suggests this criterion for carbon steel vessels with a wall

thickness of approximately 1 or more, the above described depressuring

criterion is also applied for vessels with thinner walls.

Depressuring is assumed to continue for the duration of the emergency.

The valves should remain operable for the duration of the emergency or

should fail in a full open position. Fireproofing of the control signal and

valve actuator may be required in a fire zone. As per API 521, emergency depressuring for the fire scenario should be

considered for large equipment operating at or above 250 psig (aprrox.

1700 kPag). Depressuring criteria other than those given above can be

used depending upon the specific circumstances and user-defined

requirements. For example, if there is a reactive hazard or other

exceptional hazard that can cause loss of containment due to over-

temperature, emergency depressuring can be appropriate for equipmentdesigned for a wider range of pressures than that noted above.

1.4.1 Determination of Blowdown Requirements

As mentioned above, blowdown systems are principally required to

reduce the risk of loss of equipment integrity during a fire or to reduce a

local loss of containment arising from a leak when such an occurrence

could create an unacceptable safety hazard.

In assessing whether or not blowdown valves (BDV) are required,

particular attention should be paid to equipment location with respect to

other equipment, buildings and personnel, and the contents of the

equipment in terms of quantity and composition. Figure 1.4.1 shows a

typical BDV scheme.

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Figure 1.4.1 Typical BDV scheme.

In performing the depressuring analysis it shall be ensured that

throughout depressuring the system pressure never exceeds the load

bearing capacity of the equipment. Account shall therefore be taken of

the reduction of strength with increasing temperature.

As per API 521, the depressuring system shall reduce the pressure of the

equipment within a fire zone to 50% of the design pressure or 6.9 barg

within 15 minutes. This does not imply that the depressuring stops after

15 minutes. Rotating equipment represent an exception because, due to

the loss of seal pressure, depressuring may be required in much less

than 15 minutes.

The depressuring calculation shall take into account the following:

Vaporization of the liquid due to the reduction in pressure;

Change in density of the vapour in the equipment due to the

pressure reduction and temperature increase;

Vaporization due to heat input from the external fire.

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In general, for depressuring system sizing, an initial pressure equal to

safety relief valve set pressure shall be taken into account. Compressor

systems have instead an initial depressuring pressure equal to

compressor settle out pressure. In order to evaluate compressor settle

out pressure, the following equations shall be applied:

psettle out =tot

edischedischsuctionsuction

VVpVp argarg + (4)

and for a preliminary estimate

p settle out = edischsuction pp arg3/13/2 + (5)

Sizing of depressuring valves shall be based on the assumption that,

during a fire, all input and output streams to and from the system are

stopped and all internal heat sources within the process have ceased. It

shall also be assumed when calculating the vapour load generated that

fire is in progress throughout the depressuring period.

To determine the vapour depressuring flowrates it is necessary to

establish a liquid inventory and the vapour volume of the system. This

shall include all facilities located in the fire area and all equipment outside

the fire area which, under normal operating conditions, are in open

connection with the facilities located within the fire area.

1.4.2 Sectioning of the Process Systems

In large plants, in order to reduce the design blowdown flow rate, process

sectionalizing may be considered.

Process sectionalizing is a philosophy applied to split an installation into a

number of smaller fire zones. Potential fire areas shall be identified and

clearly shown on a plot plan. For process units, depending on the

drainage design of the plot, a typical fire area of 300 m should be

assumed.

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Each zone shall be isolated by emergency shutdown (ESD) valves. Each

zone shall be provided with its own depressurizing facilities, such that

each zone can be depressurized sequentially, thereby reducing the

design peak rate.

After initiating depressurisation of the first zone, that of other zones may

be initiated as soon as the flowrate of the first zone has decayed such

that a second zone may be initiated without exceeding the design

capacity of the flare/vent system. This strategy requires equipment in an

adjacent fire zone to be adequately protected by a combination of

appropriate layout, fire walls, fire proof insulation, such that the risk of a

loss of integrity of equipment in a fire zone adjacent to the first affectedzone is insignificant.

This approach is not usually practical on an integrated offshore

production platform or in small plants; in these cases, during an ESD, all

blowdown valves open simultaneously and sequenced depressurization

using time delays is not used. Moreover, the sectioning of the process

system and time delays shall not be applied in those plants where a

single event can cause the simultaneous opening of the entire systemblowdown valve.

1.4.3 Depressuring Device Location

The location of depressuring valves shall be governed by the same

considerations as relief valves and they may discharge into the same

disposal system as the relief valves on the equipment under

consideration.

Particular attention should also be paid to the position of non-return

valves when locating depressuring valves, to ensure that equipment

downstream of the non-return valve cannot be isolated from the

depressuring valve.

Depressuring devices require periodic testing and hence the

depressuring device should be located to allow easy access.

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1.5 Layout of Downstream Piping Systems

1.5.1 Common Discharge Systems

It is usually simpler and more economic to combine discharges from anumber of facilities into a common discharge system served by a central

vent or flare.

In the normal configuration of a common discharge system designed for

venting or flaring gas at an elevated height, a knock-out drum situated

close to the stack is required to recover liquid hydrocarbon or slugs. The

relief valves or depressuring valves will discharge via plant sub-headers

with connections into a main header running outside the battery limits. If this is not possible the flare/vent piping should at least be routed through

areas where there is little possibility of a dangerous situation due to local

failure of the flare/vent piping (i.e. where possible all piping should be

welded).

The flow area through all pipe and fittings downstream a relief valve, shall

be at least the same as that of the valve outlet. The disposal piping shall

be self-draining towards the knock-out drum. In general, in order to avoid

liquid accumulation, all the relief headers shall slope continuously

towards the vent or flare K.O. drum.

If possible, connecting sub-headers shall be connected to the top of the

header; in any case, they shall drain into the headers. The sub-headers

shall be connected in such a way that there are no welds in the lower one

third of the circumference of the header.

As per API 521, the discharge piping system should be designed so that

the built-up back pressure, caused by the flow through the valve, does

not reduce the capacity below that required of any pressure-relief valve

that can be relieving simultaneously. Where conventional pressure relief

valves are used, the relief manifold system should be sized to limit the

built-up back pressure to approximately 10% of the set pressure of each

pressure-relief valve that can be relieving concurrently.

With pilot-operated valves, higher manifold pressures can be used. The

capacity of these balanced valves begins to decrease when the back

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pressure exceeds 30% to 50% of the set pressure due to subsonic flow

and/or physical responses to the high back pressure. Refer to API 520-I

for the effects of this back pressure.

1.5.2 Blockage Due to Hydrate Formation in Downstream Piping System

The blockage of discharge piping downstream of a relief or emergency

depressuring valve is not a problem under relieving or depressuring

conditions if the discharge is correctly designed.

The correct design of the discharge system should include:

sufficiently large diameter pipework (velocity < 0.7 Mach);

short length tail pipes;

the avoidance of restrictions.

To prevent hydrate or ice formation due to small leaks across the valve or

low ambient temperatures, heat tracing shall be installed.

1.6 Isolation Valves in Pressure Relief Piping

Where possible, the approach should be to use a relief valve

arrangement which does not utilise any isolation valves. This approach

eliminates the possibility of a relief valve being isolated in error. However,

for those relief devices which could have problem of plugging or other

severe problems which affect their performance, isolation and sparing of

the relief devices may be provided.

Block valves may be used to isolate a pressure relief device from the

equipment it protects or from its downstream disposal system and tofacilitate PSV / BDV inspection and maintenance without shutting down

the whole system (blowdown system included).

Since improper use of a block valve may render a pressure relief device

inoperative, the design, installation, and management of these isolation

block valves should be carefully evaluated. The ASME Boiler and

Pressure Vessel Code, Section VIII, Appendix M, discusses proper

application of these valves and the administrative controls which must be

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in place when isolation block valves are used. Local jurisdictions may

have other requirements.

1.6.1 Isolation Valves Requirements

As per API 520 Part II, all the isolation valves located in relief system

piping shall meet the following requirements:

a) Valves shall be full bore.

b) Valves shall be suitable for the line service classification.

c) Valves shall have the capability of being locked or car sealed

open.

d) When gate valves are used, they should be installed with stems

oriented horizontally or, if this is not feasible, the stem could be

oriented downward to a maximum of 45 from the horizontal to

keep the gate from falling off and blocking the flow.

An isolation valve can be used either to isolate the individual relief valve

or to isolate a complete plant section. If isolation valves are used to

isolate relief valves, there is a basic difference between the need for an

inlet valve or for an outlet valve. An inlet valve is needed if the process

cannot be shut down, whereas an outlet valve is needed if the relief

header cannot be taken out of service. Thus a single relief valve (without

a spare) connected to a relief header which cannot be shut down will

have only an outlet isolation valve.

When isolation valves are installed in pressure relief valve discharge

piping, a means to prevent pressure build-up between the pressure relief

valve and the isolation valve should be provided (for example, a bleeder

valve), see Figure 1.6.1.

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Figure 1.6.1 Typical pressure relief valve installation with an isolation valve.

A multiple relief valve arrangement with a 100% design relieving capacity

(including a spare relief valve), as the ones shown in Figure 1.6.2 and

Figure 1.6.3, will have an inlet isolation valve and outlet isolation valve.

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Figure 1.6.2 Typical pressure relief valve installation with 100% spare relievingcapacity and a three-way valve.

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Figure 1.6.3 Typical pressure relief valve installation with 100% spare relievingcapacity.

Periodic inspections of isolation valves located in relief piping should be

made which verify the position of valves and the condition of the locking

or sealing device.

1.6.2 Interlocking Systems

Where block valves are fitted upstream and/or downstream of relief

valves a system shall be in place to ensure that the required relief

capacity is always available. One method of achieving this consists in

installing of an interlocking system which makes it impossible to block off

the operating S/R valve until other similar relief capacity has been

connected to the system.

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Two situations, discharge to atmosphere or discharge to a closed system,

can occur. The following paragraphs describe correct operation to allow a

safe removal of an S/R valve for maintenance.

1.6.2.1 Discharge to Atmosphere

Spared relief valves discharging directly to atmosphere (via individual

pipes) require block valves only in the inlet pipes of the valves. These

block valves shall each be provided with a single lock, but with only one

key in total. During operation the key shall be trapped in the lock of the

closed block valve of the installed spare S/R valve. The key shall be

retractable from the lock only by locking open the block valve. Hence only

one block valve can be in the closed position at any time. The piping

between the upstream block valve and the relief valve shall be fitted with

a vent connection in order to allow depressuring before the removal of

the relief valve.

Figure 1.6.4 Typical interlocking System for pr essure relief valves w ith atmosphericdischarge.

1.6.2.2 Discharge to Closed System

Spared relief valves discharging to a closed system require block valves

in both the inlet and outlet pipes. The outlet block valves shall be

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provided with single locks, while the inlet block valves shall have double

locks. As per atmospheric discharge, the piping between the upstream

block valve and the relief valve shall be fitted with a vent connection in

order to allow depressuring before the removal of the relief valve.

Each relief valve shall be provided with a unique key which fits Lock 1 of

its inlet block valve and the lock of its outlet block valve. The key of the

outlet block valve shall be retractable only when the outlet block valve is

locked open. The key of Lock 1 of the inlet block valve shall be

retractable only when the switch key is inserted in Lock 2 of the same

inlet block valve.

Each relief valve shall be provided with a single switch key which fitsLock 2 of all inlet block valves. The switch key shall be retractable only

when the inlet block valve is locked open. This shall only be possible

when the key of Lock 1 is inserted in the lock. During operation, only the

inlet block valve of the installed spare S/R valve will be in the locked

closed position. All other block valves will be locked open. Locking open

the outlet block valve of the installed spare S/R valve (or its replacement

spool piece) prevents pressure build-up in case the inlet block valveshould leak.

The keys of the locks of the block valves of the relief valves in operation

will be trapped in Lock 1 of the inlet block valves. The switch key will be

trapped in Lock 2 of the closed inlet block valve of the spare valve. Since

the switch key is needed to unlock and close an inlet block valve, only

one block valve can be in the closed position at any time.

The key of Lock 1 of the inlet block valve of the spare valve shall bestored in the control room which shall only be accessible to authorized

personnel.

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Figure 1.6.5 Typical i nterlocking System for pressure relief valves with discharge toa closed system.

Notice that also outlet valve could be subjected to a key interlock system:

in this case the key system could avoid to close outlet valve if the inlet

valve is open (that means that outlet valve could be closed only if the inlet

valve is closed; i.e. PSV in maintenance and an other PSV in service).

1.7 Disposal System

1.7.1 General

Streams requiring disposal are:

Relief vapour and/or liquids;

Depressuring vapours;

Any operational waste streams that do not have a more suitable

outlet.

The selection of a disposal method is subject to many factors that may be

specific to a particular location or an individual unit. Disposal systems

generally consist of piping and vessels. All components should be

suitable in size, pressure rating, and material for the service conditions

intended.

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In selecting a means of disposal for these streams it is important to find a

solution in which all streams are handled with the smallest number and

diversity of systems and individual outlets.

Wherever possible disposal streams shall be collected in a closed system

and directed to a flare or vent system.

1.7.2 Atmospheric discharge

In many situations, pressure-relief vapour streams may be safely

discharged directly to the atmosphere if environmental regulations permit

such discharges.

Where feasible, this arrangement (atmospheric safe discharge) offers

significant advantages over alternative methods of disposal because of

its inherent simplicity, dependability, and economy.

1.7.3 Disposal by Flaring

The primary function of a flare is to use combustion to convert flammable,

toxic, or corrosive vapours to less objectionable compounds. Selection of the type of flare and the special design features required will be

influenced by several factors, including the availability of space; the

characteristics of the flare gas, namely, composition, quantity, and

pressure level; economics, including both the initial investment and

operating costs; and public relations. Public relations may be a factor if

the flare can be seen or heard from residential areas or navigable

waterways.

1.7.4 Flaring Versus Venting

Considerations to be made in deciding whether to vent or flare the

disposal streams are:

Impact on the environment;

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Safety and integrity of the disposal system, taking into account

that disposal streams could contain products which are not

combustible;

Local regulations;

Economic evaluations.

Considerations indicating whether venting is allowed are:

If the vapours temperature is below the auto-ignition temperature

and if they are lighter than air. Gases shall be considered to be

lighter than air if the actual density of the gas after release, taking

into account the cooling associated with expansion, is less than

0.9 times the density of the air in the area at 15 C.

If the vapours are heavier than air because of low temperature

but are in locations where the installation of a flare is

impracticable (e.g. product storage areas, marketing depots) or

where potential ignition sources are remote. In these cases the

vapours discharge velocity shall be at least 152 m/s. However,

discharge velocity shall not exceed the 80% of the sonic velocity.

If concentrations of toxic and/or corrosive components in thedispersed vapour cloud do not reach harmful or irritating levels on

nearby work levels (platforms) and outside property limits. In

order to evaluate environmental impact, calculations of effluent

emissions are required.

If the risks and consequences of accidental plume ignition (e.g.

generation of shock waves) are acceptable.

In addition to the above, streams which are not foreign to the atmospheremay be vented without environmental reservations. However, safety near

the point of discharge shall be considered, i.e. factors such as

temperature, noise, local concentrations of carbon dioxide and nitrogen,

etc.

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1.7.5 Flare and Vent Structure

The type and height of the structures supporting flare or vent stacks

depend on the following operational and environmental aspects:

Required availability of the flare and relief system;

Acceptable heat radiation levels;

Acceptable dispersion levels;

Acceptable noise levels;

Wind velocity.

There are three common stack support methods as shown in Figure

1.7.1.

The type selection is based on economical and operational grounds. A

brief structure description is given in the following.

Figure 1.7.1 Flare structures.

1.7.5.1 Self-supported

Self-supported stacks are normally the most desirable. However, they are

also the most expensive because of greater material requirements

needed to ensure structural integrity. They are normally limited

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(economically versus alternatives) to a stack height of 200 to 300 feet

(60-90 m).

1.7.5.2 Guy-wire supported

These are the least expensive but require the largest land area due to the

guy-wire radius requirements. Typical guy-wire radius is equal to one-half

the overall stack height.

1.7.5.3 Derrick supported

Used only on larger stacks where self-supported is not practical, or available land area excludes a guy-wire design.

1.8 Flare System Design

Disposal of combustible gases, vapours, and liquids by burning is

generally accomplished in flares. Flares are used for environmental

control of continuous flows of excess gases and for large surges of gases

in an emergency.

The flare is usually required to be smokeless for the gas flows that are

expected to occur from normal day-to-day operations. This is usually a

fraction of the maximum gas flow, but some environmentally sensitive

areas require 100% smokeless or even a fully enclosed flare.

Various techniques are available for producing smokeless operation,

most of which are based on the premise that smoke is the result of a fuel-

rich condition and is eliminated by promoting uniform air distribution

throughout the flames.

To promote air distribution throughout the flames, energy is required to

create turbulence and mixing of the combustion air within the flare gas as

it is being ignited. This energy may be present in the gases, in the form of

pressure, or it may be exerted on the system through another medium

such as injecting high-pressure steam, compressed air, or low-pressure

blower air into the gases as they exit the flare tip.

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1.8.1 Flare Type

1.8.1.1 Exothermic Flares

The following descriptions are for flare equipment to dispose of exothermic

flare gases; that is, gases that have a high enough heating value (usually

greater than 200 Btu/Scf (7370 kJ/Sm) for unassisted flares and 300

Btu/Scf (11050 kJ/Sm) for assisted flares) to sustain combustion on their

own without any auxiliary fuel additions.

Utility / Pipe Flare: This is the simplest flare tip; this plain design has no

special features to prevent smoke formation, and consequently should

not be used in applications where smokeless operation is required unless

the gases being flared are not prone to smoking.

Flare tips of this style, as a minimum, should include a flame retention

device (to increase flame stability at high flowrates) and one or more

pilots (depending upon the diameter of the tip).

Smokeless Flare:

Steam Injection : Flare tips which use steam to control smoking are the

most common form of smokeless flare tip. The steam can be injected

through a single pipe nozzle located in the centre of the flare, through

a series of steam/air injectors, through a manifold located around the

periphery of the flare tip, or a combination of all three. The steam is

injected into the flame zone to create turbulence and/or aspirate air

into the flame zone via the steam jets. The amount of steam required

(see API 521, 5 th Edition, Table 11) is primarily a function of the gas

composition, flowrate, and steam pressure and flare tip design.

Although steam is normally provided from a 100 to 150 psi (690-1034

kPa) supply header, special designs are available for utilizing steam

pressure in the range of 30 psi (2.07 kPa). The major impact of lower

steam pressure is a reduction in steam efficiency during smokeless

turndown conditions.

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HP Air Injection: HP air injection can also be used to prevent smoke

formation. This approach is less common because compressed air is

usually more expensive than steam. However, in some situations, it

may seem preferable, for example, in arctic or low-temperature

applications where steam could freeze and plug the flare tip/stack.

Also, other applications include desert or island installations where

there is a shortage of water for steam, or where the waste flare gas

stream would react with water. The same injection methods described

for steam are used with compressed air. The air is usually provided at

100 psi (690 kPa) and the mass quantity required is approximately200% greater than required by steam since the compressed air does

not produce the water-gas shift reaction that occurs with steam.

HP Water Injection: High-pressure water is also used to control

smoking, especially for horizontal flare applications and when large

quantities of waste water or brine are to be eliminated. One pound of

water (at 345 to 690 kPa) is usually required for each pound of gasflared.

LP Forced Air: A low-pressure forced air system is usually the first

alternative evaluated if insufficient on-site utilities are available to aid in

producing smokeless operation. The system creates turbulence in the

flame zone by injecting low-pressure air supplied from a blower across

the flare tip as the gases are being ignited, thus promoting even air distribution throughout the flames. Usually air at 0.5 to 5 kPa pressure

flows coaxially with the flare gas to the flare tip where the two are

mixed. This system has a higher initial cost due to the requirement for

a dual stack and an air blower. However, this system has much lower

operating costs than a steam-assisted design (requiring only power for

a blower). The additional quantity of air supplied by the blower for

smokeless operation is normally 10% to 30% of the stoichiometric air

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required for saturated hydrocarbons and 30% to 40% of the

stoichiometric air required for unsaturated hydrocarbons.

HP Flare: A high-pressure system does not require any utilities such

as steam or air to promote smokeless flaring. Instead, these systems

utilize pressure energy available within the flare gas itself (typically 35

to 140 kPa minimum at the flare tip) to eliminate fuel rich conditions

and resulting smoke within the flames. By injecting the flare gas into

the atmosphere at a high pressure, turbulence is created in the flame

zone, which promotes even air distribution throughout the flames.

Since no external utilities are required, these systems are normallyadvantageous for disposing of very large gas releases, both from the

economics of smokeless operation and the control of flame shape.

Maintaining sufficient tip pressure during turndown conditions is critical

and often requires that a staging system be employed to

proportionately control the number of flare tips in service with

relationship to the gas flowing.

1.8.1.2 Endothermic Flares

Endothermic gases may be disposed of in thermal incineration systems;

however, there are situations where the preferred approach is to use a

special flare design. These flares utilize auxiliary fuel gas to burn the flare

gases. With small gas flow rates, simple enrichment of the flare gases by

adding fuel gas in the flare header to raise the net heating value of the

mixture may be sufficient.

In other situations, such as gases with high CO 2 content and small

amounts of H 2S, it may be necessary to add a fuel gas injection manifold

around the flare tip (similar to a steam manifold) and build a fire around

the exit end of the flare tip that the gases must flow through.

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1.8.1.3 Enclosed Ground Flares

In general, any of the flare tips or systems discussed above may be

mounted atop an elevated stack or mounted at grade. In general, ground

flares are primarily designed for low release rates and are not effective

for emergency releases.

With increasingly strict requirements regarding flame visibility, emissions,

and noise, enclosed ground flares (see Figure 1.8.1) can offer the

advantages of hiding flames, monitoring emissions, and lowering noise.

However, the initial cost often makes them undesirable for large releases

when compared to elevated systems.

A significant disadvantage with a ground flare is the potential

accumulation of a vapour cloud in the event of a flare malfunction; special

safety dispersion systems are usually included in the ground flare

system. For this reason, instrumentation for monitoring and controlling

ground flares is typically more stringent than with an elevated system.

These flares are typically the most expensive because of the size of the

shell or fence and the additional instrumentation which may be required

to monitor these key parameters. Another significant limitation is that

enclosed ground flares have significantly less capacity than elevated

flares.

Figure 1.8.1 Enclosed ground flare.

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1.8.2 Flare Sizing

1.8.2.1 Evaluation of Flare Diameter

Flare stack diameter is generally sized on a velocity basis, althoughpressure drop should be checked.

Generally, for design proposal, a velocity of 0.5 Mach for a peak, short-

term, infrequent flow, with 0.2 Mach maintained for the more normal and

possibly more frequent conditions for low-pressure flares, is chosen.

However, sonic velocity operation may be appropriate for high-pressure

flares. Moreover, experience has shown that a properly designed and

applied flare burner can have an exit velocity of more than Mach 0,5, if pressure drop, noise and other factors permit. Many pipe flares, assisted,

unassisted or air-assisted flares have been in service for many years with

Mach numbers ranging from Mach 0,8 and higher.

The Mach number is determined as follows:

MWk

Tz

dP

WMach

f atm

=

251023.3 (6)

Where:

W Flow [kg/h]

Z Compressibility factor at flowing condition

T Temperature at vapour outlet [K]

df Flare diameter [m]

k Specific heat ratio, C p/C v

1.8.2.2 Evaluation of Flare Height

The flare stack height is generally based on the radiant heat intensity

generated by the flame. For flare radiation study, reference shall be made

to paragraph 1.11.

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1.8.3 Segregated flare systems

Depending on various factors such as plot plan, equipment design

pressures, etc., it may prove desirable to provide two or more flare

systems, such as separation of high pressure and low pressure headers.

Multiple flare system arrangements may offer significant advantages or

prove mandatory on analysis of the streams that require disposal.

Segregated flare systems may be required in order to:

Segregate sources of release into high and low pressure

systems. This may be required to enable a high pressure low

radiation tip to be used with a consequent saving on flare

structural requirements. This may also mean that only the low

pressure gas requires assistance in order to burn cleanly. As a

general rule, all pressure relief devices with an operating

pressure lower than 10 barg are collected and disposed in an LP

flare system.

Segregate sources with widely differing potentials for liquid

release.

Segregate sources of cold, dry gas from significant quantities of

warm, moist gas and thereby avoid the possibility of freezing and

hydrate formation. A relief header after passing a cold stream will

be cold. If a warm, moist gas then passes, hydrates could be

formed and block the relief header.

Segregate corrosive or potentially corrosive fluids (e.g. CO 2 and

H2S) from non-corrosive or moist fluids.

The selected design should use the minimum practicable number of

separate systems but remain operable and safe under all foreseeable

conditions. The systems installed may be totally independent, or may

share common facilities such as flare knock-out drums and flare tips in

certain circumstances.

When considering the requirement for a high and low pressure disposal

system it is necessary to consider the relief valve set pressures present in

the system. If there are a large number of high pressure sources withlarge gas volumes and a relatively few low pressure sources, then

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generally it would be more economical to install one high pressure relief

header and one low pressure relief header. An economical analysis is

usually required to ascertain the optimum number of flare systems, and to

which system each relief device should discharge.

1.8.4 Flare Disposal of Hydrogen Sulphide

Streams which are rich in hydrogen sulphide shall not be discharged into

a common HC flare or vent system unless it has been designed for this

purpose. This prevents the spreading of sour gas throughout the entire

main flare system and also avoids corrosion attack by hydrogen sulphide

and the subsequent accumulation of deposits of (pyrophoric) ferrous

sulphide.

These streams shall have a separate line-up, preferably a separate flare

stack equipped with a tip of the air pre-mix type. Alternatively, the gas

may be lined up to the bottom (downstream of the water seal) of the

hydrocarbon flare stack, but this should only be done if the hydrogen

sulphide rich flow constitutes a minor additional load.

The installation of a separate sour gas flare relief system implies

additional capital expenditure. From this point of view it is always better to

exclude such a system.

For a preliminary evaluation, the following factors should be considered

before deciding that a separate H 2S flare relief system need to be

installed or not. Sour gas release can be tied into the HC flare system in

case of:

1) continuous HC release with an H 2S content < 2% by volume;

2) intermittent HC release (only during startup and shutdown) with

an H 2S content < 20% by volume, provided this stream is less

than 10% by volume of the total continuous HC release rate;

3) emergency HC release (e.g. PSV, emergency depressuring) with

an H 2S content < 50% by volume.

When hydrogen sulphide rich gas has to be flared, incomplete

combustion can cause a hydrogen sulphide smell resulting in complaints

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by people in the vicinity. Moreover, the presence of un-combusted

hydrogen sulphide shall be dangerous for human being in the proximity of

the plant.

At a low exit velocity back burning will occur, causing sulphide stress

corrosion, especially below the refractory. This means that when H 2S rich

gas has to be released into the HC flare system more purge gas has to

be injected as well on account of the larger size of the flare, which could

offset the saving on capital expenditure.

If a hydrogen sulphide flare relief system is used, this shall be heat-traced

up to 4 m below the top of the stack. Header materials shall be carbon

steel, except for the top 4 metres of the hydrogen sulphide stack, whichshall be of AISI 310 S or equivalent.

Since no water seal vessel has to be installed, the design pressure of the

knock-out drum shall be 7 barg. To prevent flashback and consequential

detonation purge gas shall be used.

1.9 Other Flaring Equipment

1.9.1 K.O. Drum

Gas streams from relief headers are frequently at or near their dewpoint,

where condensation may occur.

A knockout drum is usually provided near the flare/vent base, and serves

to recover liquid hydrocarbons, prevent liquid slugs, and remove liquid

particles. The knockout drum reduces hazards caused by burning liquid

that could escape from the flare stack. As mentioned above, all lines downstream a relief/blowdown device

should be sloped toward the knockout drum to permit condensed liquid to

drain into the drum for removal. The locating of the flare/vent knockout

drum also needs to take into account radiation effect from the burning

flare/accidental ignition of the vent.

The economics of drum design may influence the choice between a

horizontal and a vertical drum. When a large liquid storage capacity isdesired and the vapour flow is high, a horizontal drum is often more

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economical. Also, the pressure drop across horizontal drums is generally

the lowest of all the designs. Vertical knock out drums are typically used

where the liquid load is low or limited plot space is available. They are

well suited for incorporating into the base of the stack.

1.9.1.1 K.O. Drum Pump and Instrumentation

As just mentioned, knockout drums may be of the horizontal or vertical

type; and they should be provided with a pump or draining facilities and

instrumentation to remove the accumulated liquids to a tank, sewer, or

other location. The actual type of disposal used will depend on the

characteristics and hazards associated with the liquids removed.

In the simplest system, the vessel may have only a manually operated

drain valve and a liquid-level sight glass for reference. Moreover, a liquid-

removal pump is frequently used on knock-out drums.

More elaborate arrangements may foresee high-