10004E00.pdf

Eni S.p.A. Exploration & Production Division

BEST PRACTICE

UNIT 230 RELIEF AND A ND BLOWDO BL OWDOWN WN SYSTEM SYSTEM

10004.HTP.PRC.PRG Rev. 0 – January 2008

Eni S.p.A.

10004.HTP.PRC.PRG Rev. 0 – January 2008 Sh. 2 of 93

Exploration & Production Division

INDEX

ACRONYMS

5

RELIEF AND BLOWDOWN SYSTEM – UNIT 230

6

1.1

General ............................................................................. .................................................................................................................................. ..................................................... 6

1.2

Systems Description ................................................................................... .............................................................................................................. ........................... 6

1.3

Relief System Design................................................................................................ Design............................................................................................................. ............. 7 1.3.1 Overpressure Overpressure Protection Protection Philosophy ........................................................................7 1.3.2 Upset Conditions.......................................................................................................8 1.3.2.1 Blocked Discharge..................................................................................... 8 1.3.2.2 Inadvertent Valve Opening 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 volatile material into 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................................................................................... Reaction................................................................................... 12 1.3.2.12 Hydraulic Expansion................................................................................ 12 1.3.3 Additional Consideratio Consideration n ..................................................................................... ......................................................................................... .... 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 Operating in Liquid Service ............................................................. 15 1.3.3.6 Atmospheric and and Low Pressure Pressure Storage Tanks Tanks ...................................... 18 1.3.4 Relief Devices ......................................................................................... ......................................................................................................... ................ 18 1.3.4.1 Spring loaded relief valves....................................................................... valves....................................................................... 18 1.3.4.2 Pilot-operated relief valves ...................................................................... 19 1.3.4.3 Rupture disks....................................................................................... disks ........................................................................................... .... 20 1.3.5 Relief Valves Location............................................................................................. Location............................................................................................. 20 1.3.6 Piping Upstream Upstream of a Relief Device Device ........................................................................21

1.4

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

1.5

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

1.6

Isolation Valves Valves in Pressure Pressure Relief Piping ........................................................................... 29 1.6.1 Isolation Valves Requirements......................................................................... Requirements................................................................................ ....... 30 1.6.2 Interlocking Systems ............................................................................................. ............................................................................................... .. 33 1.6.2.1 Discharge to Atmosphere ........................................................................ 34 1.6.2.2 Discharge to Closed Closed System System ................................................................... 34

1.7

Disposal System ..................................................................................... .................................................................................................................. ............................. 36 1.7.1 General....................................................................................................................36 1.7.2 Atmospheric Atmospheric discharge............................................................................................37 discharge............................................................................................37 1.7.3 Disposal by Flaring.................................................................................................. Flaring.................................................................................................. 37 1.7.4 Flaring Versus Venting............................................................................................ Venting............................................................................................ 37

Eni S.p.A. Exploration & Production Division 1.7.5


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

1.8

Flare System Design............................................................................................................ 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.......................................................................... Flares .......................................................................... 44 1.8.2 Flare Sizing ............................................................................................... ............................................................................................................. .............. 45 1.8.2.1 Evaluation of Flare Diameter ................................................................... 45 1.8.2.2 Evaluation of Flare Flare Height Height ....................................................................... 45 1.8.3 Segregated Segregated flare flare systems .......................................................................................46 1.8.4 Flare Disposal Disposal of Hydrogen Hydrogen Sulphide Sulphide .....................................................................47

1.9

Other Flaring Equipment...................................................................................................... Equipment...................................................................................................... 48 1.9.1 K.O. Drum ................................................................................................. ............................................................................................................... .............. 48 1.9.1.1 K.O. Drum Pump and and Instrumentation 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.............................................................................................. outlets.............................................................................................. 53 1.11 Flare Radiation Study ........................................................................................... .......................................................................................................... ............... 54 1.12 Relief and and Blowdown Blowdown System Highlights ............................................................................. 61 APPENDIX 1 - SIZING OF OF RELIEF DEVICES .............................................................................. 65 Design Considerations Considerations ......................................................................................... ............................................................................................ ... 65 Sizing for Gas or Vapour Relief............................................................................... Relief............................................................................... 67 Sizing for Steam Relief............................................................................................ Relief............................................................................................ 71 Sizing for Liquid Liquid Relief ......................................................................................... ............................................................................................ ... 72 Sizing for Two Two Phase Liquid-Vapo Liquid-Vapour ur Relief ............................................................ 74 Sizing for Thermal Thermal Relief......................................................................................... 74 APPENDIX 2 – HIGH INTEGRITY INTEGRITY PROTECTION PROTECTION SYSTEM (HIPS) (HIPS) ............................................ 76 Reference Documents ......................................................................................... ............................................................................................ ... 76 HIPS Justification ................................................................................................... ..................................................................................................... 78 HIPS Design............................................................................................................ Design............................................................................................................ 79 Advantages and and Disadvantages Disadvantages of HIPS................................................................ 84 GLOSSARY

87

REFERENCE

92



For Main Utilities Best Practice reference shall be made to Eni E&P internal document No. 10002.HTP.PRC.PRG.


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

TSV

Safety / Relief valve

Thermal safety valve




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.


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



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 pressurerelieving 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 valve closure, 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

Eni S.p.A.



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 carefully evaluated. 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.


Utility Failure Failure

Electric

Cooling Water Instrument Air

Steam

Fuel

Inert Gas


Equipment Affected Pumps for cooling water circulation or any other service such as boiler feed, reflux, etc. Air cooler fans, cooling cooling tower Compressors (for air, vacuum, refrigeration, etc.) Instrumentation Motor-operated Motor-operated valves Condensers and coolers Jackets on rotating equipment Transmitters / Controllers / Alarms Regulating valves Turbine drivers Reboilers Reciprocating pumps Direct steam injection equipment Boilers Engine drivers Compressors Gas Turbines Seals 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 isn’t 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.



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 safety valve (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”.



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 temperature increase 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.


(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-in system. 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:

q=

α V ⋅ φ 1000d ⋅ c

(1)

Where:

q

volume flowrate at flowing temperature [m³/s]

α V

cubic expansion coefficient for the liquid at the expected temperature [1/°C]

φ

total heat transfer rate [W]

d

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

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.



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 and overheating. 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.

pset = 1.1 ⋅ pdelivery

(2)

pset = 1.7 + pdelivery

(3)

Where:

pset

Valve set pressure [bar]

pdelivery Pump delivery pressure [bar]



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 backpressure 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



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 iqui d serv ice.

b)

For all the equipments whose upper tangent line is higher than 10.5 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.



Figure 1.3.2 - PSV in liq uid servic e.

b.2) If there isn’t a level over the equipment, the PSV shall have a minimum elevation above the upper tangent line.

Figure 1.3.3 - PSV in liq uid servic e.



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.



Conventional spring-loaded relief valves shall be installed where backpressure 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 backpressures 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.



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 nonreclosing 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.



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 top of 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 isn’t 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 (this is to avoid chatter, which will result in significant seat damage and loss of



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 the pressure 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 line of 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 inlet line, 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.



Figure 1.3.4 – PSV typ ical s cheme.

1.4

Blo wdo wn 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



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 overtemperature, emergency depressuring can be appropriate for equipment designed 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.



Figure 1.4.1 – Typic al BDV sc heme.

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.



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 =

psuction ⋅ Vsuction + pdischarg e ⋅ Vdischarg e Vtot

(4)

and for a preliminary estimate

p settle out = 2 / 3 ⋅ psuction + 1 / 3 ⋅ pdischarg e

(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 m² should be assumed.

Eni S.p.A.



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 affected zone 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 system blowdown 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

depressuring device should be located to allow easy access.

hence

the


1.5


Layout of Downst ream Piping Systems

1.5.1 Common Discharge Systems It is usually simpler and more economic to combine discharges from a number 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



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

Isolatio n 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 to facilitate 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



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.



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.



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



Figure 1.6.3 – Typical pressure relief valve installation with 100% spare relieving capacity.

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.



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 interlocki ng System f or pr essure relief v alves w ith atmospheric discharge.

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



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 fits Lock 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 valve should 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 be stored in the control room which shall only be accessible to authorized personnel.



Figure 1.6.5 – Typical i nterlocking System for pressure relief valves with discharge to a 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.



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;


•


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 the dispersed 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 atmosphere may 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.



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 struct ures.

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



(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 fuelrich 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.



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/Sm³) for unassisted flares and 300 Btu/Scf (11050 kJ/Sm³) 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: 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, 5th 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.



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 approximately 200% 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 gas flared.

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

Eni S.p.A.



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 normally advantageous 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 CO2 content and small amounts of H2S, 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 t ip that the gases must flow through.



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 – Enclos ed ground flare.



1.8.2 Flare Sizing 1.8.2.1 Evaluation of Flare Diameter Flare stack diameter is generally sized on a velocity basis, although pressure drop should be checked. Generally, for design proposal, a velocity of 0.5 Mach for a peak, shortterm, 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:

⎛ W ⎞ z ⋅ T ⎟ Mach = 3.23 ⋅ 10 −5 ⎜ ⎜ P ⋅ d 2 ⎟ k ⋅ MW ⎝ atm f ⎠

(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, Cp/Cv

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.



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 with large gas volumes and a relatively few low pressure sources, then



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 H2S 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 H2S content < 2% by volume;

2)

intermittent HC release (only during startup and shutdown) with an H2S 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 H2S content < 50% by volume.

When hydrogen sulphide rich gas has to be flared, incomplete combustion can cause a hydrogen sulphide smell resulting in complaints



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 H2S 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, which shall 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 is desired and the vapour flow is high, a horizontal drum is often more



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 liquidremoval pump is frequently used on knock-out drums. More elaborate arrangements may foresee high- and low-level alarms and level controls that operate a motorized drain valve or a liquid-removal pump. A high-level alarm to monitor the liquid level during flaring situations should be installed to alert the operators of abnormal knock-out conditions. Minimum levels in knock-out drums should be maintained to ensure sufficient free volume is available in the event of a flaring situation. 1.9.1.2 K.O. Drum Sizing It is important to realize as part of the sizing considerations, the maximum vapour release case may not necessarily coincide with the maximum liquid. Therefore, the knock-out drum size should be determined through consideration of both the maximum vapour release case as well as the release case with the maximum amount of liquid. In general, the diameter of a vertical knockout drum can be calculated from the maximum allowable vapour velocity using the following equation:

U d = 1.15 ⋅

g ⋅ D ⋅ ( ρ L − ρ V ) ρ V ⋅ C

(8)



Where:

Ud

Maximum allowable vapour velocity for vertical vessels [m/s]

g

Acceleration due to gravity, 9.81 m/s2

D

Particle diameter [m]

ρ L

Liquid density [kg/m³]

ρ V

Vapour density [kg/m³]

C

Drag coefficient determined using Figure 1.9.1

C (Re) = 2

µ

0.13 ⋅ 10 8 ⋅ D3 ( ρ L − ρ V ) µ 2

Gas viscosity [cP]

Figure 1.9.1 – Determination of drag coefficient.

This equation may be used to calculate the allowable velocity based on a particle size of 300 to 600 µm. For sample calculations, see API 521 Section 7. Moreover, tilted stacks requirements for liquid droplets sizing outgoing from the K.O. drum are more stringent than the ones for vertical stack. Table 1.9.1 shows the droplets size limit for each flare stack in case of an offshore installation. Onshore installation requires a maximum droplet size of 600 µm for both vertical and tilted stacks.

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Vertical Stack

150 µm

Tilted Stack > 45°

150 µm

Tilted Stack ≤ 45°

400 µm

Table 1.9.1 – Droplets size requirements for different flare stacks.

1.9.2 Liquid Seals Liquid seals are very common components in flare systems. Liquid seal purpose is to prevent any flashback originating from the flare tip from propagating back through the flare system and to maintain a positive system pressure to ensure no air leakage into the flare system. Liquid seals are located between the main knock-out drum and the flare stack and are quite often incorporated into the base of the stack. They are to be sized for the maximum vapour release case. Water seals are not recommended where there is a risk of obstructing the flare system due to an ice plug. Alternate sealing fluids such as glycol/water mixture may be considered. Alternatively, heating the seal fluid or draining the seal when cold temperature is detected have been used.

1.9.3 Purge System For safety purposes, a pre-commissioning and subsequent continuous purge with a non-condensable oxygen free gas is required through the flare system. The pre-purge displaces any existing air from the stack, and the continuous purge ensures that atmospheric air does not enter the stack through the flare tip during low-flow conditions. The requirements for a continuous purge might be eliminated if a liquid seal is located near the base of the stack. This requires special precautions in the design of the stack to assure viability in the event of an internal space explosion.



1.10 Vent System Design As mentioned above, pressure-relief vapour streams may be safely discharged directly to the atmosphere; it is not unusual to relieve nonflammable and non-toxic materials, such as air, steam, carbon dioxide, and water directly to the atmosphere. To protect personnel, precautions need to be taken in venting hot, cold, or high pressure materials. In certain cases, also hydrocarbon relief vapour streams may be discharged to the atmosphere. However, the decision to discharge hydrocarbons or other flammable or hazardous vapours to the atmosphere must ensure that disposal can be accomplished without creating a hazard, such as formation of flammable mixtures at grade level or on elevated structures, exposure of personnel to toxic or suffocating atmosphere, ignition of relief streams at the point of emission, excessive noise levels, corrosion, or air pollution. 1.10.1 Vent Sizing The size of a vent stack is determined by the available pressure drop and by any minimum velocity required to prevent hazardous conditions due to combustible or toxic material at grade or working levels. Therefore, in order to avoid the formation of flammable mixtures and to provide an excellent dispersion, vent size is selected to have a discharge velocity of at least 500 ft/s (152 m/s). Moreover, vent size should be checked to ensure that sonic flow is not established. The height of the vent stack is selected so that the concentration of vapour at a point of interest is well below the lower flammable limit of the vapour. Flammability consideration can be satisfied with 0.1 times to 0.5 times the lower flammable limit. The radiant heat intensity for vent stacks should also be checked in the event that a relieving vapour should ignite. This is done by the same means used for flare stacks, and the same limits apply for radiant heat intensity. Radiant heat levels sometimes take precedence over dispersion in determining stack height.

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Another factor that must be taken into account when sizing a vent stack is the

noise

level.

Eni

E&P

internal

standard,

see

doc.

no

04927.PKG.MEC.SPC, suggests, in the worst operating conditions, the noise level shall be no higher than 85 dB (A) for a radius of 50 m around the base of the flares and property limits. For vent stack noise specific calculation, see API 521, Section 7, Paragraph 7.3.4.3.

1.10.2 Individual vent outlets Where it is impractical to route discharges to a common centralised vent or flare, consideration may be given to individual local vents. The location of the vent outlet should be chosen such that:

•

Concentration of any toxic products is diluted to a safe level at any area in the vicinity where personnel are likely to be present.

•

In the event of accidental ignition of the vent, flames will not impinge upon adjacent equipment and the heat radiation to equipment or personnel will be within the limits (see Table 1.11.2).

•

Flammable vapours emanating from the vent outlet will be sufficiently diluted.

•

Noise requirements are met.

Where the atmospheric vent handles combustible vapours, the outlet from the vent should be elevated approximately 10 ft (3 m) above ground or deck within an 8 m radius. Provisions should be made for drainage of each vent pipe so that liquid cannot accumulate in the vent. The vent velocity should be as high as practicable; whenever feasible not less than

≈150

m/s (500 ft/s) at the required relief capacity, as per API

521, Section 7. For a common vent outlet the diameter shall not be smaller than the outlet of the largest connected relief valve, and is otherwise only governed by back pressure considerations.



1.11 Flare Radiation Study As mentioned above, the flare stack height is generally based on the radiant heat intensity generated by the flame. Table 1.11.1 gives exposure times necessary to reach the pain threshold as a function of radiation intensity.

Table 1.11.1 - Exposure ti mes necessary t o reach the pain th reshold .

Since the allowable radiation level is a function of the length of exposure, factors involving reaction time and human mobility should be considered. In emergency releases, a reaction time of 3–5 seconds may be assumed. Perhaps 5 seconds more would elapse before the average individual could seek cover or depart from the area, which would result in a total exposure period ranging from 8 to 10 seconds. In evaluating the exposure time/radiation intensity consideration may also be given to an exposed individual becoming incapacitated during an attempt to exit the area. As a basis of comparison, the intensity of solar radiation is in the range of 250–330 Btu/h ft² (0.79–1.04 kW/m²) depending on geographical location and time of year. Solar radiation may be a factor for some locations, but its effect added to flare radiation will have only a minor impact on the acceptable exposure time. The flare owner/operator shall determine the need for a solar-radiationcontribution adjustment to the values given in Table 1.11.2 on a case-by-



case basis. While an adjustment of 0,79 kW/m2 to 1,04 kW/m2 to a 6,31 kW/m2 (level has a relatively small impact on flare cost, the same adjustment to a 1,58 kW/m2 level results in a significant increase in cost. This determination can include, among other things, an analysis of the frequency of maximum radiation flaring, the probability of personnel or the public being near the flare during a maximum flaring incident, the probability of the sun and flame being aligned in such a manner as to have additive intensities and the ability of the personnel or the public to avoid or move away from the exposure.

Table 1.11.2 – API 521 recommended desig n th ermal radiation for personnel.

Flare system design and plant equipment layout should minimize the need for operator attendance and equipment installed in locations of high radiant heat intensity. Personnel are commonly protected from high thermal radiation intensity by restricting access to any area where the thermal radiation can exceed 6.31 kW/m2. The boundary of a restricted access area can be marked with signage warning of the potential thermal radiation exposure hazard. Personnel admittance to, and work within, the restricted access area should be controlled administratively. It is essential that personnel within the restricted area have immediate access to thermal radiation shielding or protective apparel suitable for escape to a safe location.



The effects of thermal radiation on the general public, who can be exposed at or beyond the plant boundaries, should be considered. In most cases, equipment can safely tolerate higher degrees of heat density than those defined for personnel. However, if any items vulnerable to overheating problems are involved, then the effect of radiant heat on them may need to be evaluated. A common approach to determining the flame radiation to a point of interest is to consider the flame to have a single radiant epicentre (see Figure 1.11.3) and to use the following empirical equation by Hajek and Ludwig.

D=

τ ⋅ F ⋅ Q 4π ⋅ K

(7)

Where:

D

Minimum distance from the epicentre of the flame to the object being considered [m]

τ

Fraction of the radiated heat transmitted through the atmosphere

F

Fraction of heat radiated

Q

Heat release [kW]

K

Radiant heat intensity [kW/m²]

Another factor to be considered is the effect of wind in tilting the flame, thus varying the distance from the centre of the flame, which is considered to be the origin of the total radiant heat release, with respect to the plant location under consideration. API 521 Section C presents examples of the two methods used to size subsonic flare stacks based on the effects of radiation. The first method covered is the simple approach that has been used for many years. It uses Figure 1.11.1 to determine an estimated flame length. Supposing to have a flare which releases 4.40E+09 W, the relevant flame length, using Figure 1.11.1, shall be about 100 m



Figure 1.11.1 – Flame length vs. Heat release.

The wind tilts the flame in the direction the wind is blowing. As mentioned above, assuming that a flame can be modelled by a single point source for radiation, the wind effect is obtained from Figure 1.11.2, which relates horizontal and vertical displacement of the flame to the ratio of lateral wind velocity to stack velocity. A wind velocity ( u∞ ) of 9 m/s (20 mph) is a common assumption for most radiation calculations. The flame radiation epicentre is located at the centre of a straight line drawn between the flare tip and the end of the flame.



Figure 1.11.2 - Approximate flame distortion d ue to lateral wind on jet velocity from flare stack

The second method presented in API 521 appendix C is another approach to calculating the probable radiation effects, using the more recent method of Brzustowski and Sommer. The principal difference between these methods is the location of the flame centre. The curves and graphs necessary to simplify the calculations are included in the following.



Figure 1.11.3 – Dimensional reference for flare stack sizin g.

Figure 1.11.4 – Flame centre for f lares and igni ted vents — Horizont al dist ance.



Figure 1.11.5 – Flame centre for f lares and igni ted vents — Vertical d ist ance.

The Excel Calculation Sheet (Doc. No. MOD.PRC.DDP.001) attached to this document applies the above mentioned two methods for flare sizing. For a proper application of these two methods, the following parameters shall be known:

•

Disposal gas flowrate;

•

Disposal gas molecular weight and lower heating value;

•

Gas discharge temperature, pressure and compressibility factor;

•

Disposal stream specific heat ratio;

•

Lower explosive limit concentration of flare gas in air;

•

Mach number;

•

Fraction of heat radiated;

•

Fraction of the radiated heat transmitted through the atmosphere (only for the 1st method);

•

Air temperature and relative humidity (only for the 2nd method);

•

Wind velocity;

•

Radiant heat intensity at the point being considered;


•


Minimum distance from the epicentre of the flame to the object being considered.

1.12 Relief and Blow dow n System Highlig hts In the following is given a short description of the main characteristic that must be taken into consideration during relief and blowdown system sizing and designing.

•

General: In general, the study for unit 230 sizing shall be divided in three main phases: the first one involves a PSVs study, the second one is related to BDVs, headers and flare sizing and the third one concerns with the above mentioned flare radiation study. Each phase requires care in evaluating relief / blowdown valves’ position, flowrate, etc. and during headers, K.O. drum and flare sizing. The study consists in producing a list for all plant PSVs and BDVs; the list shall contain the valve flowrate (for each valve) for each upset condition. Once determined the most severe overpressure condition (in most cases fire represents the worst overpressure condition) for each plant section, the study may proceed in headers, K.O. drum and flare sizing. Finally, the flare radiation study shall be used to determine the flare thermal radiation intensity and to evaluate the flare stack height.

•

Relief devices sizing: Set pressures and maximum relief pressures, expressed in relation to the design pressure of the protected equipment, all expressed in gauge pressures, shall not exceed the values given in the following table (strictly related to ASME VIII).

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Relief Valves Set Pressure Single Valve Max. Set Allowable Pressure Accumulated Pressure Other

than

Multiple Valves Set Pressure

Max. Allowable Accumulated Pressure

fire

exposure

• 1st valve

100

110

100

116

• Additional valves

NA

NA

105

116

• 1st valve

100

121

100

121


NA

NA

105

121

• Supplemental valve

NA

NA

110

121

Fire exposure only

Characteristic of safety relief valves for vessel protection.

•

Relief valves type: A conventional pressure relief valve is a self-actuated springloaded valve generally installed where back-pressure does not exceed 10% of the set pressure. A balanced pressure relief valve is a spring loaded pressure relief valve which incorporates a bellows to minimize the effects of back pressure. In general, balanced pressure relief valves are suitable for back-pressures ranging from 10% to 50% of the set pressure.

•

Relief valves location: During relief valves handling gas or vapour location, in order to avoid chatter and consequent seat damage, the pressure drop between protected equipment and its relief valve shall not exceed the 3% of the set pressure. Exception to this rule is represented by pilot-operated relief valves with a suitably arranged remote pilot connection close to the source of overpressure. Relief valves connected to a closed relief system shall be located above the relief header or lined up to discharge in a local drain vessel.

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•

Relief valves piping: 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. In case of two or more relief valves fitted on the same connection, the cross-sectional area shall be at least equal to the combined inlet areas of the valves. The inlet and outlet piping shall be installed without pockets to ensure that liquid does not accumulate at the relief valve outlet or inlet. In case of multiple relief valves (including one spare) discharging to the atmosphere, each valve shall have its individual discharge pipe. The discharge piping (to safe location) shall be designed as short as possible.

•

Blowdown system: API 521 suggests depressurizing to 6.9 barg or 50% of vessel design pressure, whichever is the lower, within 15 minutes. Moreover,

Eni

E&P

internal

standard

(doc.

no.

20199.VON.SAF.SDS) foresees depressurization to 50% of vessel operating pressure within 5 minutes and then to reach 7 barg within the next 10 minutes.

•

Blowdown valves location: The location of depressuring valves is governed by the same considerations as relief valves. Particular attention shall be paid to the position of non-return valves, to ensure that equipment downstream the non-return valve cannot be isolated from the depressuring valve.

•

Common discharge systems: Relief and blowdown valves will discharge via common plant subheaders into a main header connected to a K.O. drum and finally to the vent / flare. This disposal piping shall be self-drained towards the K.O. drum. In case of conventional relief valve use, the relief manifold shall be sized in order to limit the built-up back pressure to



approximately 10% of the set pressure of each pressure relief valve that can be relieving concurrently. In case of pilot operated valves use, higher manifold pressure can be observed (back pressure exceeds 30 to 50% of the set pressure).

•

Flaring vs. Venting: Environmental and safety considerations in conjunction with local regulations and economic evaluation must be taken into account when deciding whether to vent or flare the disposal streams. In general, venting is allowed if a) disposal streams are not foreign to the atmosphere; b) the vapours temperature is below the auto-ignition temperature and if they are lighter than air; c) concentrations of toxic and/or corrosive components in the dispersed vapour cloud do not reach harmful or irritating levels on nearby work levels (platforms) and outside property limits; d) the risks and consequences of accidental plume ignition (e.g. generation of shock waves) are acceptable. For more details reference shall be made to paragraph 1.7.4.

•

Typical Mach number: In order to avoid hydrate formation, headers and sub-headers shall be designed in order to have a Mach number < 0.7. Flare stack diameter is generally sized on a velocity basis in order to have a velocity of 0.5 Mach for a peak, short-term, infrequent flow and to maintain a velocity of 0.2 Mach for the more normal and possibly more frequent conditions.



APPENDIX 1 - SIZING OF RELIEF DEVICES To establish the size of a pressure relief device, the designer must first determine the conditions for which overpressure protection may be required. Reasonable care should be exercised in establishing the various contingencies that could result in overpressure. The size of the relief valve and the inlet and outlet piping shall be determined using the largest relief load. Pressure relief valves may be initially sized using the equations presented in the following paragraphs, as appropriate for vapours, gases, liquids, or two phase fluids. The designer can then use API 526, Flanged Steel Pressure Relief Valves, to select a pressure relief valve. This standard lists specific valve configurations specified by inlet/outlet size and flange configuration, materials of construction, pressure/temperature limits, inlet and outlet centre to face dimensions, and effective orifice designation.

Design Considerations As mentioned above, the size of a relief device shall be determined for the most severe individual relief condition. Set pressures and maximum relief pressures, expressed in relation to the design pressure of the protected equipment, all expressed in gauge pressures, shall not exceed the values given in Table 1 (strictly related to ASME VIII).

Eni S.p.A.



Relief Valves Set Pressure Single Valve Max. Set Allowable Pressure Accumulated Pressure Other

than

Multiple Valves Set Pressure

Max. Allowable Accumulated Pressure

fire

exposure

• 1st valve

100

110

100

116


NA

NA

105

116

• 1st valve

100

121

100

121


NA

NA

105

121

• Supplemental valve

NA

NA

110

121

Fire exposure only

Table 1 – Characteristic of s afety relief valves for vessel protection.

The overpressure used for the calculation of the relief valve can be derived from the maximum allowable accumulated pressure. This overpressure is the maximum allowable accumulated pressure minus the set pressure and the pressure drop of the piping connecting the relief valve and the vessel. The pressure drop shall not exceed 3% of the set pressure. This shall be based on the relief valve capacity. It shall also be ensured that the blowdown pressure is above the maximum operating pressure. However, if the blowdown pressure is set too close to the set pressure the relief valve may open and close rapidly causing damage to the valve. For most services the blowdown pressure will usually be 5-7% below the valve set pressure. For equipment protected by a pressure relieving device, either on the equipment itself or elsewhere within the pressure system containing the equipment, there shall be an adequate margin between the set pressure and the maximum operating pressure.



Sizing for Gas or Vapour Relief The flowrate through a relief valve nozzle is dependent on the upstream pressure and is independent of the downstream pressure as long as the downstream pressure is less than the critical-flow pressure. However, when the downstream pressure increases above the critical flow pressure, the flow through the relief valve is materially reduced. For evaluation of the critical flow-pressure, the following equation shall be used:

k

⎛ 2 ⎞ k−1 PCF = P1 ⎜ ⎟ ⎝ k + 1 ⎠

(9)

So, the sizing equations for pressure relief devices in vapour or gas service fall into two general categories depending on whether the flow is critical or sub-critical.

Critical Flow (P2 ≤ PCF) — Safety valves in gas or vapour service may be sized using the following equations:

A=

A=

131.6W T1 Z

CK d P1 K b K c MW

5.875QV T1 ZMW

CK d P1 K b K c

(10)

(11)

k+1

⎛ 2 ⎞ k−1 C = 520 k⎜ ⎟ ⎝ k + 1 ⎠

Where:

A = required effective discharge area of the device, [cm²] W = flow, [kg/hr]

(12)

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QV = flow through the device, [Nm³/hr] C = coefficient determined from an expression of the ratio of the specific heats (k = CP/Cv) of the gas or vapour at standard conditions. See Figure 2 and Figure 3.

K d = effective coefficient of discharge. For preliminary sizing a value of 0.975 could be used.

P1 = upstream relieving pressure, [kPaa]. Set pressure plus the allowable overpressure plus the atmospheric pressure.

K b = capacity correction factor due to back pressure. It can be obtained from the manufacturer’s literature or estimated. More details can be found in API 520.

K c = combination correction factor for installations with a rupture disk upstream of the pressure relief valve ( = 1.0 when a rupture disk is not installed, = 0.9 when a rupture disk is installed)

T1 = gas temperature at upstream pressure [K] Z = compressibility factor at flowing conditions MW = molecular weight of the gas or vapour V = gas velocity [m/sec].

Sub-critical Flow (P2 > PCF) — For downstream pressures greater than the critical-flow pressure, the relief valve orifice area can be calculated from the following equations:

A=

0.179W T1 Z

(13)

F2 K d K c MWP1 ( P1 − P2 )

Where:

P2 = downstream pressure at valve outlet [kPaa]. F 2 = coefficient for sub-critical flow. For a proper sizing Figure used.

1 or the following equation shall be



Figure 1– Values of F2 for sub-critical flow.

⎛ k ⎞ ( 2 F2 = ⎜ ⎟⋅r k 1 − ⎝ ⎠

Where:

r = P2 / P1

k)

⎡ (1 − r (k−1) k ) ⎤ ⋅⎢ ⎥ ⎣ (1 − r ) ⎦


Figure 2 – Gas Properties.




Figure 3 – Values of coeffi cient C.

Sizing for Steam Relief Valves in steam services are sized using the following equation (modification of Napier equation):

A=

1.904W

P1 K d K b K c K nK SH

Where:

K n = Napier’s equation correction factor. K n shall be evaluated using the following equation:

(14)

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•

If 10340 kPaa < P1 < 22057 kPaa:

•

If P1 < 10340 kPaa:

K n =

0.02764 ⋅ P1 − 1000 0.03324 ⋅ P1 − 1061

K n = 1

K SH = superheat steam correction factor (see Figure

4). For saturated

steam, for any pressure, K SH = 1.

Figure 4 – Superheat corr ection factor – K SH.

Sizing for Liquid Relief For relief valves sizing for liquid service, the following equations shall be used: Turbulent flow:

A=

7.07 ⋅ Vl G

K d K c K wK v ( P1 − Pb )

(15)



Where:

Vl = flowrate at flowing temperature and pressure, [lt/sec]. G = relative density of liquid at flowing temperature, referred to water at standard condition.

K v = capacity correction factor due to viscosity. K w = capacity correction factor due to back pressure. If the back pressure is atmospheric, use a value for K w of 1.0.

Pb = back pressure, [kPag] Laminar flow (Re < 4000): For liquids with laminar flow, the valve shall be first sized using the above equation assuming K v = 1. The so obtained discharge area, A, is compared with manufacturer standard orifice sizes and from manufacturer this is chosen the next larger orifice A’. Then, A’ is used for Reynolds number determination:

Re =

112654 ⋅ Vl ⋅ G

(16)

µ A'

With the just calculated Reynolds, using Figure

5, a first tentative value

of K v shall be obtained.

Figure 5 – Capacit y corr ection factor, K v, due to viscos ity.



In order to have an area value corrected for viscosity, A’ shall be divided by K v. If the corrected area exceeds the standard orifice area chosen, this procedure must be repeated using the next larger standard orifice.

Sizing for Two Phase Liquid-Vapour Relief For a preliminary sizing of a two phase relief valve, the following method shall be considered:

•

Determining gas and liquid relieving rates.

•

Calculating the orifice area required to gas relieving.

•

Calculating the orifice area required to liquid relieving

•

Summing total areas calculated for liquid and vapour to obtain the total required orifice area.

However, for a more rigorous solution, DIERS (Design Institute for Emergency Relief Systems) proposed an alternative method based on the classical homogeneous equilibrium model assuming no slip between the liquid phase and the vapour phase.

Sizing for Thermal Relief In case of liquid relieving rates of liquids expanded by thermal forces without vapour generation at valve set pressure and maximum temperature, the following equation shall be used.

Vl =

B⋅ Q 1000 ⋅ G ⋅ S

(17)

Where:

Q = Heat input, [W] S = Specific heat, [kJ/kg°C] B = Liquid expansion coefficient at relieving temperature, [1/°C], see Figure 6.



Figure 6 - Typical values of liquid expansion coefficient - B.

After calculating the flowrate, Vl, the relief device shall be sized applying equation (13). In order to evaluate the flowrate, in case the heat input is due to solar radiation, the interested surface area and the radiation (780-1040 W/m²) must be determined.



APPENDIX 2 – HIGH INTEGRITY PROTECTION SYSTEM (HIPS) Traditional methods of pressure relief employ a mechanical device such as a relief valve for reducing the likelihood of overpressure of vessels and piping systems. API 14C, API 521, and ASME Section VIII , Division 1 and 2 provide alternatives in the design of overpressure protection systems and suggest, as a different approach to overpressure protection, the use of an instrumented system. Any instrumented system used to provide overpressure protection is a safety-related system, since its failure would result in the rupture of the pipeline/vessel or in overloading the flare. As a safety-related system, the instrumented system must meet the international standard IEC 61508.

Reference Documents The High Integrity Protection System shall be in accordance with the following standards: API 521 recommends the use of High Integrity Protection System (HIPS) only when the use of pressure relieving devices is impractical (e.g. due to extreme field investments).

API 14C (standard for offshore production platform safety systems) provides a design exemption for the substitution of HIPS for pressure relief valves (PRV) in wellhead, header and pipeline applications. API 14C does not provide a specific exemption for pressure vessels.

ASME Code Case 2211 sets the conditions under which overpressure protection may be provided by an instrumented system instead of a pressure relief valve (PRV). This ruling is intended to enhance the overall safety and environmental performance of a facility by utilizing the most appropriate engineered option for pressure protection. While there are no specific performance criteria in the Case Code, the substitution of the HIPS for the PRV should provide a safer installation. Consequently, the



substitution is generally intended for limited services where the PRV may not work properly due to process condition, e.g. plugging, multiple phases, raising temperature above thermal decomposition point and causing an internal detonation or fire, etc. The overpressure protection can be provided by a Safety Instrumented System (SIS) in lieu of a pressure relieving device under the following conditions: a)

The vessel is not exclusively in air, water, or steam service.

b)

The decision to utilize overpressure protection of a vessel by system design is the responsibility of the user. The manufacturer is responsible only for verifying that the user has specified overpressure protection by system design, and for listing Code Case 2211 on the Data Report.

c)

The user must ensure the maximum allowable working pressure of the vessel is higher than the highest pressure that can reasonably be expected to be encountered by the system.

d)

A quantitative or qualitative risk analysis of the proposed system must be made addressing all credible overpressure scenarios.

e)

The analysis in (c) and (d) must be documented.

IEC 61508 The objective of these standards is to define the design and documentation requirements for SIS. One of the most important criteria for SIS design is the requirement that the user assigns and verifies the Safety Integrity Level (SIL) for the SIS. The assignment of SIL is a corporate decision based on risk management philosophy and risk tolerance. Safety instrumented systems (SIS) should be designed to meet a safety integrity level, which is appropriate for the degree of hazard associated with the process upset. Safety integrity levels per IEC 61508 are designated in the following table:

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Exploration & Production Division Safety Integrated Level (SIL) 4 3 2 1

Availabili ty Required > 99.99% 99.90 ÷ 99.99% 99.00 ÷ 99.90% 90.00 ÷ 99.00%

Probabilit y to Fail on Demand (PFD) E-005 E-004 E-003 E-002

to E-004 to E-003 to E-002 to E-001

1/PFD 100000 to 10000 10000 to 1000 1000 to 100 100 to 10

Table 2 – Safety int egrity level.

HIPS Justification A decision tree can be utilized to facilitate the justification for HIPS in the process industry. Figure 7 is a simplified decision tree showing the key steps in assessing and designing a HIPPS.

Figure 7 – Simpli fied design tree.



HIPS Design Once the decision is made to implement HIPS, a safety requirement specification must be developed to address various overpressure scenarios and the actions required to mitigate the scenario. The frequency of overpressure of vessels is often high, due to process upsets or inadvertent block-in of vessels. When the frequency and consequence are considered, SIL 3 is often selected. In other words, when all of the layers of protection are considered, the availability of the HIPS should be sufficiently high to cause the overpressure of the vessel to be essentially a “non-credible” event. A HIPS is a trip system consisting of three basic elements: the field input devices, the logic solver and the final elements. As with other trip systems, the purpose of HIPS is to protect life, to protect the environment and/or assets and production. They do differ from a regular trip system in the high level of availability required. This is achieved through the redundancy in system components. Since the HIPS results in process shutdown, there is often significant economic impact to the plant due to loss of production when there is a spurious trip. Consequently, these systems also have high reliability requirements. A quantitative verification of the SIL should be performed to ensure that the target SIL is met. The important parameters when considering HIPS design are as follows:

•

Voting

•

Field input devices

•

Logic solver

•

Final control elements

•

Diagnostics

•

Testing, and

•

Common cause failures.

It is also absolutely critical to quantify the availability of the system. In fact IEC 61508 highly recommend a quantitative evaluation of SIL. This verification can also be used to establish the required testing and



maintenance program for each HIPS once the device, architecture, and voting have been selected.

Voting Configurations: The purpose of using a voting scheme is to increase the integrity of the system and/or to minimize spurious trips. A two-out-of-three (2oo3) voting scheme is frequently used in HIPS. One-out-of-two (1oo2) voting will improve availability of a system but will significantly increase the nuisance trip rate. Two-out-of-two (2oo2) voting will improve the reliability of the system but will decrease the safety factor or availability of the system. Two-out-of-three (2oo3) voting (see Figure

8) combines the benefits of

high availability and high reliability. The voting system works by initiating the trip function only when at least two of the input devices are in the trip state. Spurious trips are reduced and, if testing procedures are properly written and followed, inputs can be tested without bypassing.

Field Input Devices: The process variables commonly measured in HIPS are pressure, temperature and flow. Traditionally, switches were used as the process sensor in SISs. Nowadays, with the evolution of Programmable Electronic System (PES) technology, the use of transmitters to measure these variables is now preferred. Switches only give a change in output when they are activated and can “stick” or experience some other failure mode that is revealed only when the switch is tested or a demand is placed on it. Redundant transmitters are not subject to these same covert failures and their use has a positive effect on the system. Moreover, transmitters can be continuously monitored and the operability of the transmitters readily observed. With transmitter redundancy employed, out-of-range/deviation alarming and median select can be implemented to ensure a high level of availability. Most HIPS applications require 2oo3 transmitters on all field inputs, utilizing median select and deviation alarming from the median.


Separate process connections (see Figure


8) are also recommended to

decrease common cause faults, such as plugged impulse lines.

Figure 8 – 2oo3 transmitters’ typical scheme.

Logic Solver: This hardware must meet the required SIL, which often means that it must comply with SIL-3 performance requirements, as provided in IEC 61508. The logic solver can be relays, solid state or Programmable Electronic Systems (PES). If a PES is used, it must provide a high level of selfdiagnostics and fault tolerance. Redundancy of signal paths and logic processing is necessary, and the trip output function must be configured as de-energize to trip. IEC 61508 requires that the safety logic be separate and independent from the basic process control system; therefore, in order to reduce the probability that both functions would become contemporary unavailable, HIPS is separated from the Basic Process Control System.

Final Control Elements: The final control elements in HIPS are usually two shutdown valves in series working in a 1oo2 configuration. On-line testing provisions should be provided to permit each valve to be function tested independently.



Solenoid valves, configured as de-energize to trip, are used to actuate the block valves. Solenoids can be configured 1oo2 to maximize safety availability, but spurious trips are a problem (see Figure

9). These

valves can be configured 2oo2 or 2oo3 to reduce spurious trips (see Figure

10). The 2oo2 configuration will require more frequent testing

than a 2oo3 configuration to maintain acceptable availability. The solenoids should be mounted as close to the valve actuator as possible, to decrease the required transfer volume for valve actuation. Finally, the exhaust ports should be as large as possible to increase the speed of the valve response.

Figure 9 - Final Contro l Elements show ing 1oo2 solenoids.



Figure 10 - Final Control Elements show ing 2 oo2 solenoids.

Diagnostics: The ability to detect failures of components on-line significantly improves the availability of the HIPS; therefore, diagnostic capability should be designed into all HIPS.

Testing: Testing is performed to uncover failures. If safety system components are not tested, dangerous failures reveal themselves when a process demand occurs, causing an unsafe event that the safety system was designed to prevent. The appropriate testing of a SIS utilized as a HIPS is key to ensure that the availability requirements are satisfied. Architecture, redundancy and device integrity have a significant effect on the probability to fail on demand and therefore testing frequency requirements. To determine the appropriate testing frequency, a quantitative risk assessment shall be done; ISA TR84.02 (1998) recommends one of the following methods:

•

Markov Models

•

Fault Tree Analysis (FTA)

•

Simplified Methods



Common Cause Failures (CCF): CCF in HIPS design should be assessed. A CCF occurs when a single fault results in the corresponding failure of multiple components. Thus, CCFs can result in the HIPS failing to function when there is a process demand placed on it. CCFs must be identified during the design process and the potential impact on the HIPS functionality understood. There is a great deal of disagreement among the experts on how to define CCF and what specific events comprise a CCF. The following are often cited as examples of common cause faults:

•

Miscalibration of sensors

•

Plugging of common process taps for redundant sensors

•

Incorrect maintenance

•

Improper bypassing

•

Environmental stress on the field device

•

Process fluid or contaminant plugs valve

The most critical failure is that the safety requirement specification (SRS) is incorrect at the beginning of the design process and the HIPS cannot effectively detect the potential incident.

Advantages and Disadvantages of HIPS It is poor safety practice to install and rely on pressure relief devices in services where the sizing of the device is poorly understood or known to be inadequate due to chemical reactions, multiphase fluids, or plugging. In these applications, alternatives, such as HIPS, should be examined to ensure mitigation of overpressure events. Industry is increasingly moving towards utilizing HIPS to reduce flare loading and prevent the environmental impact of pressure venting. They are becoming the option of choice to help alleviate the need to replace major portions of the flare system in existing facilities when adding new equipment or units.



If the header and flare system must be enlarged, significant downtime is incurred for all of the units that discharge to that header. The capital and installation cost associated with HIPS is attractive when compared to the downtime or equipment cost of flare modification. Another benefit is that the process unit will not flare as much as a process unit designed for full flare loading. In some areas of the world, this is becoming important as regulatory agencies place greater restrictions on flaring of process gases. The main disadvantage of HIPS is the careful documentation, design, operation, maintenance, and testing to ensure standard’s compliance. Specific regulatory and enforcement jurisdiction requirements must be determined. In some instances, approval of local authorities is required. Regulatory and standards requirements must be understood by all parties, including facility management and instrumentation and electrical, operations, and maintenance personnel. Any justification for HIPS must be thoroughly documented through a hazard analysis, which identifies all potential overpressure scenarios and demonstrates that the HIPS can adequately address each scenario. HIPS systems are more complex, requiring the successful functioning of multiple devices to achieve the performance of a single pressure relief device. The user must verify that HIPS will work from a process standpoint and that the HIPS design results in an installation as safe as or safer than a conventional design. The effectiveness of the system is highly dependent on the field design, device testing, and maintenance program. Consequently, the user must understand the importance of application-specific design aspects, as well as the associated costs of the intensive testing and maintenance program whenever a HIPS is utilized. When a pressure relief device is not installed or is undersized based on conventional design, the HIPS becomes the “last line of defence,” whose failure potentially results in vessel rupture. Finally, there is no “approved” rubber stamp in any regulation or standard for the use of HIPS for reduction in the size of relief devices and associated flare system for pressure vessels or pipelines. Substantial cautionary statements are made in the standards and recommended



practices, concerning the use of HIPPS. No matter what documentation is created, the user still has the responsibility to provide a safe and environmentally friendly operation.

Eni S.p.A.



GLOSSARY ACCUMULATION

Pressure increase over the maximum allowable working

pressure of the equipment being protected during discharge through the pressure relief valve. Expressed in pressure units or as a percentage of MAWP or design pressure.

ACTUAL DISCHARGE AREA

Net area of a selected orifice which dictates

the pressure relief valve relieving capacity.

ATMOSPHERIC DISCHARGE

Release

of

vapours

and

gases

from

pressure-relieving and depressuring devices to the atmosphere.

BACK PRESSURE

Pressure existing at the outlet of a relief device as a

result of the pressure in the discharge system. It is the sum of the superimposed and built-up back pressures.

BALANCED PRESSURE RELIEF VALVE

Spring-loaded

pressure-relief

valve that incorporates a bellows or other means for minimizing the effect of back pressure on the operational characteristics of the valve.

BLOWDOWN Depressurization

of a plant or part of a plant, and

equipment.

BUILT-UP BACK-PRESSURE

It is the increase in pressure at the relief

device outlet that develops as a result of flow after the pressure relief device opens.

COEFFICIENT OF FLOW (CV)

Defined as the actual flow performance in

U.S. gallons of water per minute at 60 °F when inlet pressure is 1 psig and outlet pressure is atmospheric (14.7 psia). CONSTANT BACK PRESSURE

constant with time.

Superimposed

back

pressure

which

is

Eni S.p.A.



DESIGN PRESSURE Value selected for the design of equipment for the

most severe condition of coincident pressure and temperature expected in normal operation, with provision for a suitable margin above these operating conditions to allow for operation of the pressure relief valve. EFFECTIVE DISCHARGE AREA A nominal or computed area used with an

effective discharge coefficient to calculate the minimum required relieving capacity for a pressure relief valve.

ELEVATED FLARE

Flare where the burner is raised high above ground

level to reduce radiation intensity and to aid in dispersion.

ENCLOSED FLARE Enclosure with one or more burners arranged in such

a manner that the flame is not directly visible.

FLARE Device or system used to safely dispose of relief gases in an

environmentally compliant manner through the use of combustion.

FLARE BURNER / FLARE TIP

Part of the flare where fuel and air are

mixed at the velocities, turbulence and concentration required to establish and maintain proper ignition and stable combustion.

FLARE HEADER

Piping system that collects and delivers the relief

gases to the flare.

GROUND FLARE

HIPS

Non-elevated flare.

High integrity protection system. Instrumented system used for

overpressure protection as an alternative to traditional relief devices.

HYDRATE

Solid, crystalline compound of water and a low-boiling-point

gas, in which the water combines with the gas molecule to form a solid.

Eni S.p.A.



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.

KNOCKOUT DRUM Vessel in the effluent handling system designed to

remove and store liquids.

LIQUID SEAL / WATER SEAL

Device that directs the flow of relief gases

through a liquid (normally water) on the path to the flare burner, used to protect the flare header from air infiltration or flashback, to divert flow, or to create back pressure for the flare header.

MACH NUMBER

Ratio of a fluid’s velocity, measured relative to some

obstacle or geometric figure, divided by the speed at which sound waves propagate through the fluid.

MAXIMUM ALLOWABLE WORKING PRESSURE

Pressure

determined

by

employing the allowable stress values of the materials used in the construction of the equipment. It is the least value of allowable pressure value found for any component part of a piece of equipment for a given temperature. It is the maximum gauge pressure permissible at the top of a completed vessel in its normal operating position at the designated coincident temperature specified for that pressure.

OPERATING PRESSURE

Pressure

expected

during

normal

system

operation.

OVERPRESSURE

relieving device.

The pressure increase over the set pressure of the

Eni S.p.A.



PILOT-OPERATED PRESSURE-RELIEF VALVE

Pressure

relief

valve

in

which the major relieving device or main valve is combined with and controlled by a self-actuated auxiliary pressure-relief valve (pilot).

PRESSURE RELIEF DEVICE

A device actuated by inlet static pressure

and designed to open during an emergency or abnormal condition to prevent a rise of internal fluid pressure in excess of a specified value.

PRESSURE-RELIEF VALVE

Valve designed to open and relieve excess

pressure and to reclose and prevent the further flow of fluid after normal conditions have been restored.

PURGE GAS

Fuel gas or non-condensable inert gas added to the flare

header to mitigate air ingress and burn-back.

RADIATION INTENSITY

Local radiant heat transfer rate from the flare

flame, usually considered at grade level.

RELIEVING CONDITIONS Inlet pressure and temperature on a pressure-

relief device during an overpressure condition.

REQUIRED DISCHARGE AREA A nominal, or computed, area of a pressure

relief valve used in recognised flow formula to determine the size of the valve. It will be less than the actual discharge area.

RUPTURE-DISK DEVICE

Non-reclosing pressure-relief device actuated by

static differential pressure between the inlet and outlet of the device and designed to function by the bursting of a rupture disk.

SET PRESSURE

Value of increasing inlet static pressure at which a

pressure relief valve begins to open.

SIL

Safety Integrity Level.

Eni S.p.A.



SIS

Safety Instrumented System.

SET PRESSURE

Inlet gauge pressure at which a pressure-relief device

is set to open under service conditions.

SUPERIMPOSED BACK PRESSURE

is the static pressure that exists at the

outlet of a pressure relief device at the time the device is required to operate. It is the result of pressure in the discharge system coming from other sources and may be constant or variable.

VAPOUR DEPRESSURING SYSTEM

Protective arrangement of valves and

piping intended to provide for rapid reduction of pressure in equipment by releasing vapours.

VENT HEADER

Piping system that collects and delivers the relief

gases to the vent stack.

VENT STACK Elevated vertical termination of a disposal system that

discharges

vapours

into

the

conversion of the relieved fluid.

atmosphere

without

combustion

or



REFERENCE The following documents have been the main reference for the development of Unit 230 Best Practice.

2007

ANSI / API Standard 521 5th Edition, January 2007 Pressure-Relieving and Depressuring System

2005

Eni E&P Internal Standard Doc. No. 04927.PKG.MEC.SPC Rev. 01, January 2005 Gas Plant – Atmospheric Vent Flares – Extinguishing System

2004

GPSA – Engineering Data Book 12th Edition (Electronic), 2004

2003

API Standard 537 1st Edition, September 2003 Flare Details for General Refinery and Petrochemical Service

2001

Protect Plants against Overpressure Wing Y., UOP LLC Chemical Engineering, 2001, Vol. 108, n° 6, p. 66 – 73

2001

Eni E&P Internal Standard Doc. No. 20199.VON.SAF.SDS Rev. 01, August 2001 Installazioni a terra – Criteri generali di sicurezza

2000

API Recommended Practice 520 Part I – Sizing and Selection 7th Edition, January 2000 Sizing, Selection and Installation of Pressure-Relieving Devices in Refineries

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