Section 12 - Safety in Design & Pressure Relief.pdf

8/15/2019 Section 12 - Safety in Design & Pressure Relief.pdf

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Slide 12.2

Safety In Process Design

General Principles – The Design of Safety Into a Process is the Responsibility of the

Process Design Engineer. – Every Design Must be Safe Against Reasonable Causes of Failure.

Adequate Facilities Must be Incorporated Into the Design to PreventFires, Explosions, and Accidents and to Minimise Releases.

– All Process Designs (Grass-Roots and Revisions) are Subject toHAZOP Review and by pertinent Safe Operations Committees toEnsure that Safety Standards are Being Followed.

– The Need for OIMS Compliance


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Slide 12.3

References For Safety In Process Design

1. API Recommended Practices 520, Parts I and II, and 521.2. ASME Code, ANSI Standard B31.33. PC Models Available for Network Analyses.4. Air Pollution Calculations - Dispersion Models5. Within ExxonMobil:

– ExxonMobil Design Practices, Section XV, – Global Practices – Local Engineering Standards


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Slide 12.4

What’s a Contingency?

Abnormal events that cause an emergency situation

A unit’s safety facilities are designed to handle the load resulting from the limitingcontingency.

To develop a contingency, consider all direct effects. For example:

– If loss of instrument air causes a valve in the cooling water circuit to fail closed...then boththe air failure and loss of cooling water must be considered simultaneously.

– Multiple units may be effected:

– Power Failure

– Reformer upset causing loss of hydrogen, etc.


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Slide 12.5

Contingency Evaluation Assumptions

Consider only one contingency at a time. Assuming two unrelated contingencieswill occur simultaneously is not warranted.

Immediately prior to an emergency, plant was in a normal operating condition.

All normally operating equipment continues to function if it is not directly part of the

contingency.

Blowdown valves and pressure control valves normally closed should not beassumed to be operable in a emergency and credit should not be taken for theircapacity when determining relief rates.

Normally open valves not directly part of the contingency are assumed to remainopen -- Okay to take credit to reduce relief rate.


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Slide 12.6

Contingency Types

Two types:

Design Contingencies - Fire, Utility Failure, Mechanical Failure or Operator Error

Remote Contingencies - Abnormal events with an extremely low probability thatare not considered a design contingency. Examples include: – Interrelated double contingencies which could develop pressures or temperatures

sufficient to cause catastrophic failure, or result in large releases – Heat exchanger tube failure

– Inadvertent closure of car sealed open (CSO) valve

– Inadvertent opening of car sealed closed (CSC) valve

– A control valve failing open with its bypass fully open

– Upside down rupture disk

– Plugging of a fixed bed catalyst bed


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Slide 12.7

More on Remote Contingencies

ASME code does not directly address remotecontingencies, so they should not be the sizingcontingency for the PR valve.

Remote contingencies are not part of the designbasis, but equipment must be checked to ensureit won’t fail during a remote contingency.

Equipment allowed to exceed the designpressure by 1.5 times, or to the hydrotestpressure, whichever is less.

If the PR valve relief area for the remotecontingency calculated based on the "1.5 TimesRule" exceeds that calculated for designcontingency, size the valve based on the remotecontingency.


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Slide 12.8

Interpretation of PRV Sizing for Remote Contingencies

Basis (DP XV-C p. 25)

"Remote Contingency Rule" - The additional load caused by the remote contingency (to which the “ RemoteContingency Rule " is applied) need not be considered in calculations of flare and PR valve radiant heat levels. For situations where the required relief area calculated for the remote contingency on the basis of the " RemoteContingency Rule " exceeds the relief area installed for the limiting design contingency, or when the remote contingency

is the only overpressure scenario applicable to a pressure relief valve, the required PR valve relief area must becalculated on the basis of considering the situation which would otherwise be considered a remote contingency as adesign contingency. The ASME Code does not recognize remote contingencies; hence, a remote contingency is not anacceptable basis for the design/installation of PR devices stamped to the ASME Code (where the accumulation in theprotected system is limited to 10% of the Design Pressure of the system for single PR devices or 16% for multiple PRdevices.)

If remote contingency sizes safety PRvalve, increase normal contingency rateuntil normal contingency sizes PR valve.


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Slide 12.9

Design Contingencies - Fire

STRATEGY:

– Set up fire zones within an onsite unit whereequipment is separated by at least 20 feet (6.1

m) in all directions ( In calculating fire loads, it isassumed that all of the equipment in a singlefire zone is exposed to fire ).

– Calculate heat transferred into the equipment(see next slide)

– Then calculate the PRV load based on thelatent heat of the liquid.

Basis (DP XV-C p. 29)

“The Fire Risk Area for the purpose of determining overpressure protection are established by the provision ofaccessways or clear spacing at least 20 ft wide on all sides with drainage to catch basins located with in the FireRisk Area, which permit fire fighting attach into all parts of the area and which limit the spread of fire. Clear spaceunder pipebands, if more than 20 ft wide is considered as acceptable separation between Fire Risk Areas for thepurpose of determining overpressure protections. The selection of single Fire Risk Areas within a plan or unit must,in addition, consider the design of the drainage system and the equipment layout.. These should be selected tolimit the extent of the Fire Risk Area to no more than 5000 ft²


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Slide 12.10

Calculating Fire LoadsHEAT INPUT

– For equipment with good drainage, use the equation:

Q = 21,000 F A 0.82 (customary)

Q = 43.2 F A 0.82 (metric)Where: Q = Total heat absorbed by the equipment Btu/hr (kW)

A = Total wetted surface of the equipment which absorbs heat, ft 2 (m 2)F = Environmental factor

– For facilities that lack good drainage the equation changes to:

Q = 34,000 F A 0.82 (customary)

Q = 70.9 F A 0.82 (metric)

VAPOR LOAD

Calculate the vapor load by converting the heat input to the equipment to vaporload using the following equation:

W = Q / L

Where: W = Vapor generated, lb/hr (kg/s)L = Latent heat of vaporization, Btu/lb (kJ/kg)


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Slide 12.11

Calculating Fire Loads (Cont.)

WETTED SURFACE AREA

Total wetted surface within 25 ft (7.5 m) of grade or other surface which could sustaina fire (e.g. solid platform). In the case of vessels containing a variable level of liquid,use the HLL.

Horizontal DrumsFor vessel elevations up to 25 ft (7.5 m) above gradeuse total vessel wetted surface up to high liquid level.For vessel elevations more than 25 ft (7.5 m) above

grade use total wetted surface to high liquid level or upto vessel centerline, whichever is less.

Vertical DrumsThe wetted surface within 25 ft (7.5 m) of grade, basedon high liquid level, is used. If the entire vessel is morethan 25 ft (7.5 m) above grade, then only the surface ofthe bottom head need be included.


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Slide 12.12

Calculating Fire Loads (Cont.)

Fractionators and other Towers An equivalent "tower dumped" level is calculated byadding liquid holdup on the trays to the liquid at high liquidlevel hold up at the tower bottom. If the entire vessel is

more than 25 ft (7.5 m) above grade, then only the surfaceof the bottom head need be included.

Storage Spheres and Spheroids

The total exposed area within 25 ft (7.5 m) ofgrade, or up to the elevation of the centerline,whichever is greater.

Heat Exchangers, Air Fins and PipingThe surface area of a tower reboiler and itsinterconnected piping should be included in thewetted surface of exposed vessels in the risk area.The fin area of air fin exchangers and piping area,other than that for reboilers, are not normallyincluded in the wetted surface area.


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Slide 12.13

Calculating Latent Heat of VaporizationCalculate at different % vaporizedCan take adjustment for changing wetted area, if applicable – See DP XV-C Appendix A

Automatically calculated in PEGASYS

– Note this is not a true “Heat of Vaporization” because it includes heat to raisethe temperature of the bulk fluid, but is the correct value to use

Fire Release CalculationCalculated in PEGASYS, Safety Valve Sizing Module

0

50

100

150

200

250

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

% Vapori zed

Heat of Vaporization (Btu/lb)

Release Rate (klb/h)

Maximum Release


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Slide 12.14

Design Contingencies - Utility Failures

The most common utility failures are: – Electric Power – Cooling Water – Steam – Instrument – Air – Fuel – Nitrogen

Utility failures can have unexpected consequences. It is necessary to consider all ofthe possible effects and interrelationships.


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Slide 12.15

Emergency Conditions Example Of Util ity Failure(C.W.)

PRV

Water

Assume: Stays inNormal Position

Gas

Prod

Overhead Condenser Water Failure


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Slide 12.16

Plant Cooling Water Failures For PRV Sizing

NormalContingency

CoolingWater Return

*

X Unit

Unit

Unit

Cooling Water Supply

*

RemoteContingency

Failures

+ Closure ofgate valve(s) isa normalcontingency

+ Line break isusually aremotecontingency

+ Closure ofgate valve(s) isa normalcontingency

+ Line break isusually aremotecontingency


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Slide 12.17

Design Contingency - Equipment Failureand Operator Error Equipment is subject to individual mechanical failure; contingencies include:

– pumps – compressors – fans – mixers – instruments – control valves (which might fail open or closed)

Operator or human error, such as opening or closingthe wrong valve, is considered a design contingency.

Operator error is most likely to occur when the unit isupset and the operators are very busy.


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Slide 12.18

Emergency Conditions, Example Of Equipment Failure(Blowthrough)

Fails Open

Bypass Valve

Tower

PRV Atmos. or Flare1. Assume bypass 50% ofCV normal operating Cv,

CV fully open - limit towerto 110% of design p res(normal contingency)

2. Assume bypass and CV ful lopen - limit tower overpressureto lower of 150% of DP or testpressure (remote contingency)

3. Assume bypass c losed;CV fully open; towerblocked in; gas flow only –limi t tower to 110% ofdesign pres (startupcondition)


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Slide 12.19

Emergency Conditions Example Of Operating Failure

Pump Shutoff P = 500 psiMax. Suction Pressure = 50 psigMax. Discharge Pressure = 550 psig

D.P.=550 psig D.P.=550 psig

Set at300 psig

LiquidDischarge

D.P.=300 psigDesalter

PRV

D.P.=550 psig


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Slide 12.20

Design Contingency - Exothermic Reactor

Usually protected by high-temperature cutouts that automatically depressure thereactor system when the temperature reaches a predetermined level. Theprotection system may be initiated by situations in addition to high reactortemperature, such as loss of feed flow. (We will discuss this later.)

Protection may also be achieved by responses other than depressurization. Theseresponses depend on the configuration of the individual unit, and may include: – shutting off the flow of reactants – tripping feed and/or treat gas heaters


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Slide 12.21

Design Contingencies - Liquid OverfillPR valves are often located in the vapor space of partially filled liquid vessels such as towers,drums, etc. which could overfill during a plant upset. If overfill can result in a pressure abovethe design pressure of the vessel, the PR must be sized for overpressure from liquid overfillconsidering the higher of:

– stoppage of liquid outflow with maximum operational fill rates

– increased liquid fill rates with outflows at turndown rates

The overfill must be considered as a design contingency unless all of the following areprovided:

– The vessel has an safety critical independent high level alarm (LHA). *

– The vessel vapor space above the LHA is equivalent to a minimum of 30-minute holdupwith a design inlet rate and the outlet rate stopped.

– The vessel has a safety critical high-level cut-out (LHCO) on all liquid feeds designed toprevent overfill *. Level Instruments for LHCO are independent from the LHA and normal

controls. – The total safety critical LHA/LHCO system should have a high overall availability (99+%),

with at least one component (LHA or LHCO) achieving 97% availability.

* LHA and LHCO will be designed to GP-15-07-02 standards and will function for all possible process conditions and will functionduring all instance where liquid discharge from the PR device is possible (including startup and shutdown)

a2


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Slide 21

a2 I summarized the 7 criteria from pages 36 of DP VX-C (2008) to 4 points.ashotru, 10/1/08


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Slide 12.22

Thermal Expansion

Lines or equipment which can be left full of liquid under non-flow conditions andwhich can be heated while completely blocked-in must have some means ofrelieving pressure that may build up due to thermal expansion of the containedliquid.

Protection against thermal expansion may be provided by one of the followingmethods:

– Installation of a PR valve.

– Installation of a small permanently open CSO bypass around one of the block

valves per GP 03-02-04. An alternative could be a drilled hole in all of theblock valves (or check valve) as long as the leakage is acceptable andaccounted for in the design. *

– Safety critical procedures ensuring that blocked in equipment is drained ofliquid. *

(* These may not be permitted by local codes.)


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Slide 12.23

Heat Exchanger Tube Splits

Whatever the cause, the possibility of overpressuring equipment on the lowpressure side of the exchanger is the result. Since it is a remote contingency, the1.5 rule applies.

In this case, the low pressure side of the exchanger must be protected by pressurerelief devices if the design pressure on the high pressure side is more than 1.5times the design pressure on the low pressure side and the low pressure sidecannot handle the discharge from a split tube without exceeding 1.5 times thedesign pressure on the low pressure side.

Tube splits, unlike the other special contingenciesdiscussed previously, are considered a remotecontingency.

In a shell and tube exchanger, the tubes are subjectto failure from a number of causes, including: – thermal shock – vibration – corrosion


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Slide 12.24

Tube Split Primer

When possible, design low pressure side for minimum 2/3 of high pressure side – Meets “2/3 rule”, so no analysis is required – Logic: maximum pressure achievable is 150% of design (remote contingency)

If low pressure side does not meet “2/3 rule”:

– Verify low pressure side does not exceed 150% of design pressure during tube splitCalculate high pressure fluid rate entering low pressure side for tube split – 1 tube (two severed tubes ends) for most cases – 10 tubes if 1000 psi (70 kg/cm 2) pressure difference and an active corrosion

mechanism

Adiabatically flash leaked high pressure fluid to 150% of low pressure designpressureCompare: – New low pressure piping velocity (of leaked high pressure fluid) – Low pressure fluid velocity before leak occurred

If velocity had to increase, pressure relief is requiredSome exceptions exist for double pipes, tubular reactors, and “low stress” tubes Always check for ¼” (6.4 mm) tube leak as a normal contingency, including when takingHX out of service


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Slide 12.25

Heat Exchanger Leak

Provide PR valve if leak would overpressure low pressure side during: – Normal operation – Operational upset could block in low pressure side – Downstream valve (control, EBV, block) could block in low pressure side

Exception for manual block valve at exchanger if: – Low pressure side is also cold side – HX meets 2/3 rule – Warning signs installed preventing blocking before high pressure side

is blocked


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Slide 12.26

Explosion Caused By Operating Error (Closing The Drain On aBlocked-in, Unblinded Exchanger, with tube leak)

Crude Leak in No. 1 Cooler Operator Closed C & D (LP Hot Side)Operator Closed A & B (HP Cold Side)

Operator Opened Drain on Shell SideOperator Closed Drain on Shell Side

Exchanger Blew Up (high pressure crudeleaked through valve and into low pressure

side and overpressured shell)

P/S

Leaks

Crude 425 psig

7 psig

A

DB

C

1 2 3


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Slide 12.28

FurnacesIf There is a Restriction or Valve in the Outlet Line, PRVs are Required. If the Outlet Valveis Car Sealed Open (CSO), a PRV MIGHT be Avoided. However, an outlet block valve is notnormally necessary

- Normally Preferred - Only When Feed Contains Liquid, and:-Required if Feed is All Vapor - PRV Would Coke on Outlet(To Provide Continued Flow) - PRV Cannot be Purged

PRV PRV

Requirements For PRVs (Cont’d)


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Slide 12.29

VACUUM CRUDE O/H

0 PSIG

120 F

25

PSIG

FLARE

VACUUMCOMPRESSOR

OR FURNACE

NC

6"

OIL PUMPS

Blowthrough


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Slide 12.30

VACUUM CRUDE O/H

0 PSIG

120 F

25

PSIG

FLARE

VACUUM

COMPRESSOROR FURNACE

NC

6"

OIL PUMPS

CSC

Blowthrough (Cont’d)


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Slide 12.32

Pressure Relief Valves

Last resort to protect equipment from overpressuring

Required by codes (i.e. ASME Boiler & Pressure Vessel Codes, ANSI B31.3(Petroleum Refinery Piping), and ANSI B16.5 (Flanges & Flanged Fittings).

These codes specify: – All pressure vessels subject to overpressure shall be protected by a PRV

Some locations may require all vessels have PRV

– Liquid filled vessels or piping subject to thermal expansion must be protected by a thermalrelief device.

– Multiple vessels may be protected by a single PRV provided there is a clear, unobstructedpath to the device.

No flame/detonation arresters, normally no control valves

– At least one PRV must be set at or below the design pressure.


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Slide 12.33

Requirements For Pressure Relief Valves

– Vessel+ Any Vessel that can be Overpressured Must Be Protected by a PRV

PRV PRVNo ValvesBetweenVessels

+ Per ASME Code Case 2211 allows vessels less than or equal to 2 ft in diameter made of piping componentsthat are not stamped, ASME coded vessels to be protected by system design (i.e. no PSV).


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Slide 12.34

Multiple Pressure Relief Valves

When to use multiple PRVs: – If the valve area required is larger than the largest available PRV – To better match contingency flow rates with valve capacity to avoid potential "chattering". – If multiple PRVs are more economical than one very large valve due to mechanical design

considerations.

PRV design and set point when two or more valves are used: – One of the PRV’s must be set at the design pressure (or MAWP); additional valves can be

set up to 5% above the design pressure (or MAWP). – Non-fire contingency, design valves based on 16% accumulated pressure in the vessel. – Fire contingency, a supplemental valve designed to handle the fire load can be set as high

as 10% above the design pressure, and the capacity should be calculated based on 21%accumulation


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Slide 12.35

Conventional Relief Valve

The conventional relief valve is usedfor the majority of refinery andchemical plant services.

This spring loaded, top-guided, highlift, nozzle-type pressure relief valvecan handle a maximum built-up backpressure of 10% of set pressure(except for fire, where 21% isacceptable).


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Slide 12.36

Conventional Relief Valve OperationThe operation andcharacteristics of a conventionalPRV are shown graphically.

This figure conforms to therequirements of Section VII ofthe ASME Boiler and PressureVessel Code. The pressureconditions shown here are forpressure relief valves installedon a pressure vessel. Allowable

set-pressure tolerances will be inaccordance with the applicablecodes.

Diff B PRV i V d Li id


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Slide 12.37

Differences Between PRVs in Vapor and LiquidService

VAPOR – PRVs are specifically designed for "pop" action. (i.e. they move to the full open

position at only a slight overpressure). The valve remains fully open as thepressure builds to the permissible maximum, when the rated capacity is fullydischarged.

LIQUID – PRVs are designed to lift progressively with rising pressure until the full open

position is reached.


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Slide 12.38

Balanced Bellows Pressure Relief Valve

Balanced bellows PR valves are similarto conventional PR valves, but aredesigned to minimize the effect of backpressure on valve performance.

Back pressure affects conventional andbalanced bellows valves differently.


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Slide 12.39

Conventional vs Balanced Bellows PRV’s

Conventional valve. Back pressureincreases set pressure.When back pressure fluctuates on aconventional valve, the valve may open attoo low a pressure or permit the vessel to

exceed equipment rating, depending uponthe back pressure adjustment and springpressure adjustment.

Balanced bellows valve. Back pressurehas little effect on set pressure.The balanced bellows achieves balancingof the valve disc by venting the interior ofthe bellows thorough the bonnet chamber

to the atmosphere. Venting arrangementsmust be carefully designed, because anybellows failure or leakage will permitprocess fluid from the discharge side to bereleased to the atmosphere.


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Slide 12.40

When to Specify Bellows Valves

High / Fluctuating Back Pressure : Back pressure has little effect on balancedbellows set pressure. When back pressure fluctuates on a conventional valve, thevalve may open at too low a pressure or permit the vessel to exceed equipmentrating.

Fouling or Corrosive Service : Balanced bellows PRV’s are used in theseservices because the bellows shields the spring from the process fluid.

High Back Pressure : The balanced bellows PRV’s can be used at considerablyhigher back pressure than conventional PRV’s:

Total back pressure (super imposed plus build-up back pressure) up to 50% of PRVset pressure.

In retrofits, the back pressure may rise up to 75% of the set pressure, but will result inreduced capacity (contact PRV vendor).


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Slide 12.41

Pilot Operated Relief Valve

Pilot operated relief valves havea main valve that is combinedwith and controlled by a self-actuated auxiliary PR valve (orpilot valve). These valves useprocess pressure instead of aspring to keep the valve closed.


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Slide 12.42

Pilot Operated Relief Valve: Advantages

Pilot operated relief valves have several advantages, summarized below.

RetrofitsThey may be used in retrofit situations where there is less margin betweenoperating and design pressure, because simmer does not start until about 98% of

set pressure.Less ChatteringThey are less subject to chattering, because they can be designed as“modulating”, only opening as much as is necessary. This is especially importantfor a liquid PR valve with a long inlet line.

High Back PressureThey can be used with backpressures as high as 50% to 75% of set pressure, ifthe backpressure is accounted for in sizing the valve.

Depressuring DeviceThey can be used as a depressuring device. Using a remote bleed valve, pressuremay be bled from the piston chamber, causing the valve to open at less thanthe set pressure.


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Slide 43


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a4 This information may be mis leading, Anderson Greenwood Crosby mentioned that the cost of a pilot operating PSV is less than aconventional for valves larger than a 4P6. Because of the cost of steel.ashotru, 10/1/08


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Slide 12.44

PRV Applications

The following table summarizes relief valve applications.

Conventional BalancedBellows

Pilot

Temps > 400 °F (205 °C) X X

Dirty/Corrosive Service X

Temperature Above Autoignition X

Clean Service < 400 °F (205 °C) X X X

Varying Backpressure X X

High Built-up Backpressure X X

Operating Close to Set Pressure X


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Slide 12.45

Chatter

Causes of chatter include: – Excessive inlet pressure drop – Excessive built-up back pressure – Oversized valve (The oversized valve must have at least 25% of capacity

utilized.) – Valve handling widely differing rates – Excessive inlet line length, especially for liquid service

Non-piping solutions to preventing chatter include: – Installing a smaller PRV – Installing a different type of PRV

– Increasing blowdown


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Slide 12.46

Rupture Discs

A rupture disc (RD) is a thin disc, usually made ofsolid metal, that is designed to rupture (or burst)at a designated pressure.

Unlike PR valves, a RD is non-reclosing; the burst

RD provides a permanent open path into thedischarge system. The discharge system mayeither be the atmosphere or a closed system suchas a flare header.

There are five major types of RD’s described in

DP Section XV-C. One type is shown here.


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Slide 12.47

Advantages of Rupture Discs

No simmering or leakage - Unless the RD is corroded or damaged, there is nosimmering or leakage prior to bursting.

Open ful ly, rapidly - RD's open fully very rapidly, so they are good foroverpressure caused by an internal deflagration or sudden pressurization (for

example, as a result of a tube failure in a high pressure exchanger).Less expensive corrosion resistance - It is less expensive to provide corrosionresistance for a rupture disc than for a conventional or balanced bellows reliefvalve. RD’s can be made of or coated with a variety of corrosion resistantmaterials.

Less fouling or plugging - There is less tendency for a rupture disc to foul orplug. The RD opening is essentially equal to the piping bore.

Overpressure/depressure use - RD's can provide both overpressure anddepressuring protection.

Lower cost - A rupture disc can be provided at a lower initial cost than anequivalent service PR.


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Slide 12.48

Disadvantages of Rupture Discs

Sensit ivity to temperature - Since burst pressure depends on disc materialproperties, the temperature at the time of burst will cause the burst pressure tovary. The choice of material has a great influence on sensitivity to pressure, as thegraph shows.

Non-reclosing - If the burst RD is the only protective device, it must be replacedbefore operations continue. If the RD is used in series with a PR valve, operationscan continue without replacing the burst disc. However, the extra protectionafforded by the RD is lost until the burst disc is replaced.

Destructively tested - Non-destructive testing of the RD burst pressure cannot be

accomplished. Unlike PR valves, which can be adjusted, the accuracy of the burstpressure is solely based on manufacturer’s tests from the same lot.

Require periodic replacement - Require periodic replacement. Most vendorssuggest RD replacement annually, but under more severe conditions morefrequent replacement may be necessary.

Easily damaged - Rupture discs are more sensitive to mechanical damage thanother pressure relief devices.


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Slide 12.49

Rupture Pins

A rupture pin is designed to be a non-reclosing pressure relief device, similarto a rupture disc. A piston is held in theclosed position with a buckling pin thatprecisely senses axial force, and willfail at a set pressure according toEuler's Law. An O-ring on the piston isused to make a bubble tight seal.

T f R Pi D i


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Slide 12.50

Types of Rupture Pin Devices


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Slide 12.51

SAFETY VALVES FILM

Sizing Vapor Valves:


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Slide 12.52

Determining if Critical Flow Exists

The formulas used to size vapor PR valves depend upon whether the valvesoperate with critical or choked flow. This condition occurs when the flow throughthe nozzle equals the speed of sound or sonic velocity.

Equation 3 in DP XV-C (shown below) can be used to determine whether a valvehas critical flow.

There will be sonic flow if the pressure relief valve's outlet pressure is equal to orless than P x.

Sizing Vapor Valves


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Slide 12.53

Sizing Vapor ValvesThe following equation is used to calculate the required orifice area regardlessof whether the flow is critical or subcritical or PV type (conventional orbalanced) provided that the correct back pressure correction factor anddischarge coefficient are used.

Note: Pegasys may also be used to size these valves.

Sizing Liquid Valves


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Slide 12.54

Sizing Liquid Valves

PR valves in liquid service have no critical pressure limiting the flow of through aPR valve orifice, as is the case for vapor service. The discharge rate for non-flashing liquid through the PR valve is a function of the pressure drop across thevalve, but sizing equations depend on the valve type:

Certified valves. This new type of valve is recommended for all services where thefluid is a non-flashing liquid except for fire. These valves will reach full capacity atno more than 10% accumulation.

Older type valves. These valves are recommended for all services where the fluidmay contain some vapor at times. They were used for all liquid services prior to

about 1985. They do not fully lift until 25% accumulation is reached.Pegasys may be used to size both certified and the older type valves.


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Slide 12.56

PROBLEM #11

Selecting the PR Valve


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Slide 12.57

Selecting the PR Valve

Table III-2 in DP XV-C shows the valve models available as a function of temperature,flange rating and orifice size. The table provides model numbers for Crosby and Farrisvalves, which are the most common types.

Designing Inlet Piping


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Slide 12.58

Designing Inlet Piping

PRESSURE DROP

– Less than 3% of set pressure (psig) at safety valve rated capacity

SIZING

– At least size of PR valve inlet – For multiple PR valves, cross-sectional area of manifold line equal to sum of

all inlets

ORIENTATION

– Must drain freely back to source of fluid (no traps)PREVENTION OF PLUGGING

– Heat tracing if plugging by ice or wax

– For coking, provide continuous purge of clean fluid

REMOVAL OF PR VALVE DURING OPERATION

– Install bleeder between inlet block valve and PR valve

Valve Discharge Location


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Slide 12.59

Valve Discharge LocationPR valves can discharge to:

– a closed system (This can be a flare system, or the discharge may be returned to theprocess.)

– the atmosphere

Discharge to the atmosphere is permitted in only a few instances: – PR valve handling vapor only at valve inlet AND

– Liquid overfill is a remote contingency AND

See also new requirements preventing liquid discharges to atmosphere

– Potential liquid release is water or similar non-hazardous liquid at a temperature below150°F (65ºC) AND

– Discharge to closed system not otherwise required AND

– Local regulations are followed. AND

It is preferable for PR valves to discharge to a closed system when:

– The vapors discharged would be significant contributors to atmospheric pollution, but donot fall into any of the "required" categories.

– Connecting to an adjacent closed header (providing that capacity is available) is lesscostly than an atmospheric discharge line to a safe location.

Outlet Line Back Pressure Constraints


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Slide 12.60

Outlet Line Back Pressure Constraints

For single or multiple PRV releases discharging under a single-risk contingency:

– Built-up back pressure is limited to:

10% of set pressure for conventional type PR valves for operating contingencies

21% of set pressure for conventional type PR valves for fire contingencies

– Total back pressure (built-up + superimposed) is limited to 50% of setpressure for balanced bellows type PR valves for either operating or firecontingencies and 70% for pilots

Superimposed back pressure on the non-discharging PR valves in the systemduring a maximum system release (single contingency) shall not exceed:

– 25% of lowest set pressure for conventional type PR valves

– 75% of lowest set pressure for balanced bellows / 80% pilot PR valves

Mechanical design of the PR valve shall take into account any limitations imposedby the back pressure

Outlet Piping Design Additional Constraints


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Slide 12.61

p g g

Discharge line size should not be less than safety valve outlet flange size

Velocity in discharge piping should not exceed 75% of sonic

Discharge piping should not contain any restrictions or liquid traps and shouldslope downwards to the collection header/blowdown drum.

Atmospheric Discharge Riser need to be:

– 10 ft (3 m) above top platform

– 50 ft (15 m) horizontal distance from other equipment

– Discharge vertically

– No restrictions: check valves, flame arrestors or orifice plates – Maximum velocity = 75% of sonic

– Minimum velocity = 100 ft/s (30 m/s) if flammable, at 25% of rated capacity

Install snuffing steam if relief to atmosphere at a temperature above auto ignition.

Install Toroidal Ring if relieving Hydrogen or Methane to atmosphere

CSO valves must have stems horizontal or vertical downwards.

PRV Discharge Piping


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Slide 12.62

Set at100 psig

APRV

Both Valves are Relieving

PRVPres Normally 0 psig

Set at400 psig

- For Conventional Safety Valve, Max Pres @ A = 10 psig

- High Outlet Line Pressure Drop Will Cause Valve “ Chatter”

- For Balanced Bellows Valve, Max Pres @ A = 50 psig

- Discharge Line Size should not be less than Safety Valve Outlet Flange size

- Velocity in Discharge Piping should not Exceed 75% of Sonic

- Discharge Piping should not contain any liquid traps and should slopedownwards to the Collection Header

Other Back Pressure Considerations In DischargeCircuit


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Slide 12.63

APRV

PR Valve at A is Not Relieving

PRV

Pres Normally 0 psig

Set at

400 psigSet at100 psig

- For Conventional Safety Valve, Max Pres @ A = 25 psig

- For Balanced Bellows Valve, Max Pres @ A = 75 psig

Emergency Isolation, Depressuring And ShutdownSystems


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Slide 12.64

Systems

Facilities to Stop the Uncontrolled Release of Toxic orFlammable Materials (“Minimising the Damage”):

– Emergency Isolation

– Emergency De-pressuring

– Emergency Shutdown

– Water Flooding Provisions

Emergency Isolation and EBVs


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Slide 12.65

There are four types of EBV’s, designated A, B, C, and D. The design specificationdesignates which type of valve should be installed for each service. The types varywith respect to the:

– minimum distance from the equipment protected (at equipment to 40 ft or 12maway)

– means of activation ( manual to push button at various locations)

– maximum elevation and accessibility

However, all of these valves must be capable of being stopped in mid-travel andreturned to normal position.

Types of EBV’s


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Slide 12.66

APPLICABL E RESTRICTIONS FOR VALVE TYPEREQUIREMENT

A B C D

VALVE LOCATION• Horizontal distance from source

of potential leak At equipment > 25 ft (7.5 m) (1)(4) > 25 ft (7.5 m) (1)(4) No restrictions

• Maximum elevation above grade At equipment 15 ft (4.5 m) (2) 15 ft (4.5 m) (2) No restrictions

VALVE SIZE & FLANGE

RATINGS• Recommended for

All sizes and classes = 8 in. (200 mm) or Class 300 and lower (3)

> 8 in. (200 mm) or Above Class 300 (3)

All sizes and classes

PUSH-BU1TON FOR ACTIVATION• Push-button location Not applicable Not applicable At valve > 40 ft (12 m) from

source of leak (4)

• Operable from Not applicable Not applicable Grade or platform Grade

• Maximum elevation above grade Not applicable Not applicable 15 ft (4.5 m) (2) At grade

ACCESSIBILITY• Valve can be reached without

passing the source of potentialleak closer than

Not applicable 25 ft (7.5 m) (4) 25 ft (7.5 m) (4) Not applicable

• Push-button can be operatedwithout passing the source of potential leak closer than

Not applicable Not applicable 25 ft (7.5 m) (4) 40 ft (12 m) (4)(5)

Notes:(1) This distance increases to 40 ft (12 m) for manually operated block valves in process, fuel and pilot gas lines to fired heaters.

(2) If the valve is more than 75 ft (23 m) horizontally from source of potential leak, or identified as “Battery Limit (BL)” valve, there areno restrictions on elevation or flange class.(3) EBV's located at Battery Limits normally are either Type B or C. Type C EBV's are required at the battery limit only in flammable or

toxic services for valves larger than 8 in. (200 mm).(4) For marine pier facilities, this distance is 100 ft (30 m)(5) For pressurized and refrigerated storage facilities (e.g., LPG) the push-button should be located outside

of the dike.

Equipment Requiring EBV's


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Slide 12.67

The following equipment often require EBV's:

Compressors of 200 HP (150 kW) and higher handling flammable or toxic gasesrequire EBV's in suction and discharge.

Pumps require EBV's in the suction lines when:

– The inventory in the suction vessel is over 2000 gals (7.5 m 3) of flammable or4000 gals (15 m 3) of combustible liquid.

– Toxic liquid released from a seal failure would result in an excessiveconcentration at the fence line.

Vessels may require EBV’s on certain connections depending on the type andamount of inventory in the vessel.

Fired heaters, boilers and other combustion devices generally require EBV'son the fuel line and on lines carrying flammable process fluids to the fired heatercoils.

Equipment Requiring EBV's (Cont.)


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Slide 12.68

Vulnerable equipment such as graphite exchangers containing flammable or toxicmaterials, which are exceptionally vulnerable to fracture and uncontrolled releaseas a result of thermal or mechanical shock, generally require EBV's.

Battery l imits EBV's are generally required for all process and utility streams

entering or leaving battery limits if the line is normally pressurized.Battery limits are the boundaries of the smallest geographical boundaries of aprocessing equipment area which are separated by at least 50 ft (15 m) fromadjacent facilities, and which contain either a process or a group of integratedprocesses which may be shut down together for a turnaround.

EBVs summary (see charts on DP XV-F)


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Slide 12.69

EBV(A): Normal block valve installed at equipment nozzle.EBV(B): Normal block valve 25’ (7.5m) from equipment. Must be 8” and 300# or less, not higherthan 15’ (4.5m) of grade. BLBV can be higher flange rating and size for non-flammable/non-toxic,and higher elevation.EBV(C): Motor operated valve 25’ from equipment not higher than 15’ of grade. Button at valve.EBV(D): Motor operated. Button at grade 40’ (12m) from equipment. Recommend button in controlhouse also. Fireproof valve if within 25’ of fire source.Toxic Materials – EBV(D) w/control house button if small connection or flange leak exceeds fence line

concentration limit. Applies even to piping.Compressors – EBV(D) on suction and discharge for 200 hp (150 kW) handling flammable or toxic gases

Pumps – Depends on vessel size, liquid flammability or toxicity, and EBV location2,000 (7.5 m 3) and 4,000 (15 m 3) gallon break pointsSome piping large enough to be considered

Vessels – Depends on vessel size, liquid vapor pressure or toxicity, and line size

Most 2” and smaller lines below liquid level will require EBV(A) – Place EBV directly on vessel nozzle – 1,000 (3.8 m 3) and 10,000 (38 m 3) gallon break points

Furnaces – EBV(B) required for all feeds and fuels, EBV(D) if within 40’ or above 15’ elevation

Emergency Depressuring


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Slide 12.70

Quick Removal of the Flammable Inventory Reduces the Duration of a Fire. Vapor Blowdown facilities are used for the Purpose.

Equipment Requiring Vapor Blowdown Facilities:

Operating above 150 psig (10.5 kg/cm 2g) where vapor is in continuous phase andthere is no liquid inventory, e.g. Powerformer Reactor.

Operating above 250 psig (17.6 kg/cm2g) when the flammable liquid and vapor contents of a vessel would exceed 200,000 ft 3 (5600 m 3) when expanded toatmospheric pressure.

Blowdown connection shall have Type D EBV actuated from control room and shoulddischarge to the flare system.

Connection is typically sized to reduce equipment pressure from its operating value to50% of its design pressure in 15 minutes for fire emergency.

Oversizing should be avoided as this can result in excessive flare or lifting of a catalystbed.

Blowdown connections may discharge into closed release system header or intoseparate vapor depressurising header to the flare.

EMERGENCY DEPRESSURE GUIDELINES DP XV-F


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Slide 12.71

Emergency Shutdown Systems


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Slide 12.72

Provide a Quick Remote Way of Shutting Down Equipment

ESDs are Independent of Controls (Cannot be Emphasised Enough!)

Shutdown Controls Must be Designed with Suitable Guards and for OnstreamTesting Without Shutting Down the Equipment.

Emergency Shutdown Systems are Required for:

– Drivers

All Compressors > 200 HP (150 kW)

Steam-Driven Pumps and Compressors that Handle Flammable Materials

– Fired Heaters

– Air injection / Oxidiser Streams to Process

– Refrigerated Liquid/Gas Facilities

– Claus Plants, Gas Turbines, Air Preheaters, Reactors such as Hydrocrackingwith Potential for Runaway

Water Flooding Provisions


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Slide 12.73

Protects against uncontrolled release of flammable material at the vessel bottomconnections or at the pump withdrawing liquid from it.

Injected water displaces the liquid hydrocarbon up the vessel, so that only waterescapes.

Water is required at a pressure higher than the vessel pressure plus the statichead.

Vessel temperature to be not below 40°F (5°C) or Above 200 °F (93°C).

Water flooding to be considered for large non-refrigerated volatile inventories, e.g.LPG Spheres.

Types of Vapor Discharge Systems


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Slide 12.74

Closed System -- Conventional Flare – Handles the majority of releases from PRVs

– Also used to drain K.O. Drums, Emergency vaporblow downs / liquid pull downs, vapor liquiddiversion, etc.

To Atmosphere via Condensable BlowdownDrum (totally condensed and > 32°F or 0ºC).

Segregated H 2S Flaring System - used forcontinuous (greater than 30 minutes) release ofH2S. Some risk of plugging problems.

Other Segregated Closed Systems

Components of a Typical System


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Slide 12.75

Flare headers collect the effluent from variousPR valves and sends them to the blowdownDrum.In addition, drain headers receive drainage fromother hydrocarbon containing vessels such asfuel gas knockout drums, compressor drums,reactors, etc. and send it to the blowdown drum.

The flare header and drains discharge in the blowdowndrum . This drum:

Separates the liquid from the vapor before the vaporis send to the seal drum.Collects hydrocarbon liquid and water.

There are two types of blowdown drums:Non-condensable blowdown drumCondensable blowdown drum

Flare gas from the blowdown drum is sent to the sealdrum , where flare gases are discharge under water toprovide a seal to prevent flashback in the event that acombustible mixture was present. A continuous flow ofwater is maintained to the seal drum to sure that the sealwill always present.

Flare disposes of vapor streamsby safely by burning under

controlled conditions. Three typesof flares are available:Elevated FlareGround FlareBurning Pit

The elevated flare is the mostcommonly used in refineries and

chemical plants.

The ignitor or pilot ignites gasflowing through the flare stack.

Typical Non-Condensable Blowdown Drum


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Slide 12.76

Flare Types


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Slide 12.77

COMPARISON FACTORS ELEVATED FLARE MULTIJET FLARE BURNING PIT FLARE

Pollution Characteristics• Smoke

• Noise

• Luminosity

• Air Pollution (odor)

• Can be made smokelessexcept at high loads.

• Noisy, due to steam used for smoke reduction (compromisenecessary).

• High, but can be reduced withsteam.

• Best obtainable, if elevation isadequate.

• Relatively smokeless

• Relatively quiet

• Some

• Poor dispersion, because of low elevation; severe problemsif poor combustion or flameout.

• Poor

• Relatively quiet

• Some

• Poor

Other Factors • High cost if high elevation.• Visual and noise pollution.• Radiation requires wide

spacing.

• High cost.• High maintenance

requirement.• Odor pollution at low elevation.• Hazardous if flameout occurs.

• Low-cost and simple; butpollution is not

• acceptable in most cases.• Wide spacing required.

Appl ic ation • General choice for total flareload, or as over-capacity flarein conjunction with multijetflare.

• Generally the only acceptable

flare where products of combustion or partialcombustion are toxic or malodorous.

• Use for base load or partialflaring rates if noise and visualpollution are critical.

• Suitable only for "cleanburning" gases, i.e. where

products of combustion are nottoxic or malodorous.• Not suitable upwind of

residential areas.

• Remote locations where nopollution requirements applyand space is available.

Flare Design Considerations


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Slide 12.78

The location, spacing and height of the flare is set by considering:

the radiant heat densities.

possible burning of liquid fallout.

possible pollution problems

Radiant Heat Densities


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Slide 12.79

This table shows radiant heat densitylimits:

DP XV-E, Appendix A shows the amountof time personnel can spend as a functionof the heat density.

LOCATION Btu/hr-ft 2

Property Line 500

At Grade Below Flare 3000

Equipment 10,000

kW/m 2

1.6

9.5

31.5

Heat Density Requirements


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Slide 12.80

Flares should be as high as any platform or building within500 ft (150 m), and in no case less than 50 ft (15 m).Flare location and height must meet all applicableregulatory standards for noise requirements.

Any source of ignitable hydrocarbons such asseparators or floating roof tanks should be atleast 200 ft (61 m) of the base of the flare.

Flares must be 200 ft (61 m) from propertylines and not exceed a heat density of 500Btu/hr-ft 2 at the property lines.

Glossary


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Slide 12.81

AUTOIGNITION TEMPERATURE - The lowest temperature required to cause self-sustaining combustion, without ignition by spark or flame. (Typical 600ºF).

FLAMMABLE (EXPLOSIVE) LIMITS - Minimum and maximum concentrations offlammable vapor in air which support combustion.

FLASH POINT - Lowest temperature at which liquid exposed to air gives offsufficient vapor to form a flammable mixture.

FLAMMABLE LIQUID - Liquids with Closed-cup Flash Point below 100°F or liquidwith flash above 100°F when temperature is above or within 15°F of flash point.

COMBUSTIBLE LIQUID - Liquids with Closed-cup Flash Point above 100°F whentemperature is less than (Flash Point - 15°F).

HIGH FLASH STOCKS - Flash points 100°F or greater.

LOW FLASH STOCKS - Flash points less than 100°F or stocks at temperaturesabove or within 15°F of its flash point.

LIGHT ENDS - Material having an RVP > 15 psia. (Reid vapor pressure, i.e.,vapor pressure @ 100ºF) (e.g. pentane and lighter).

Glossary (Continued)


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Slide 12.82

PYROPHORIC MATERIAL - A material that is spontaneously combustible whenexposed to air at ambient temperature.

TOXIC MATERIAL - A material capable of causing injury on reaching sites in or onthe human body. (i.e., Phenol, H2S, HF Acid, Benzene, NH3, etc.)

FIRE ZONE - Area containing the smallest group of equipment that can beapproached from all sides by fire-fighting equipment and personnel. Regardless ofaccessibility, vessels with a horizontal distance of 20 feet of each other are in thesame fire zone. Maximum area normally limited to 5,000 Sq. Ft.

MAWP - The highest pressure to which a vessel may be subjected continuously.

MAWP is determined based on vessel wall thickness selected.DESIGN PRESSURE - That is used as a basis for determining minimum shellthickness, usually the same as MAWP (MAWP ≥ Design Pressure).

CONTINGENCY - An abnormal event that is the cause of an emergency condition.(e.g., Loss of cooling water).

SINGLE RISK - The equipment affected by a single contingency. (e.g., Fire).

Glossary (Continued)


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Slide 12.83

SET PRESSURE - The inlet pressure at which the pressure relief valve is set toopen.

ACCUMULATION - The pressure increase over MAWP during discharge through apressure relief valve.

OVERPRESSURE - The pressure increase over set pressure during dischargethrough a pressure relief valve.

BACK PRESSURE - The pressure on the discharge side of a pressure relief valve.

SUPERIMPOSED BACK PRESSURE - The pressure on the discharge side of apressure relief valve before it opens.

BUILT-UP BACK PRESSURE - Increase in pressure at valve discharge resultingfrom flow through that valve.

DIFFERENTIAL SPRING PRESSURE - Set pressure minus the superimposedback pressure for a conventional valve. For pilot operated and balanced bellowsvalves, the spring pressure equals the set pressure.

Section 12 - Safety in Design & Pressure Relief.pdf

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