Why This Module Is Important - Active Learnercloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/PRS-RFS/PRS-RFS-1.pdfHeating and Cooling Medium Potential Causes of

Why This Module Is Important

If we are interested in process safety, we need to understand thebasics of relief and flare, including depressuring

The Marsh incident database, published every year, consistentlyshows fire and explosion as the leading cause of loss in most ofthe major incidents

Our understanding of relief and flare also affects how we operateand maintain our facilities, and how we respond to emergencies

If we do not have a good understanding of the principles thatgovern relief and flare design and operation, we are not likely toadequately update and maintain our relief and flare system

Overpressure

Relief and Flare Systems Core

Relief and Flare Systems Core ═════════════════════════════════════════════════════════════════════════

© PetroSkills, LLC. All rights reserved._____________________________________________________________________________________________

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Learning Objectives

This section will cover the following learning objectives:

Classify and discuss the typical causes of overpressure

Identify the overpressure protection options



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Potential Causes of Overpressure – Inadvertent Closure

Inadvertent closure of discharge block valve, e.g.

• Closed block valve from earlier shutdown/maintenance notopened prior to startup

• Control valve or shutdown valve closes

Inadvertent opening of a valve from a source of higher pressure, e.g.

• Level control loop or valve failure on high pressure separatorresults in loss of level and gas blow-by to lower pressureseparator

• Pressure control valve failure, e.g. fuel gas scrubber

Potential Causes of Overpressure – Inadvertent Opening



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Power

Fuel Gas

Instrument Air

Heating and Cooling Medium

Potential Causes of Overpressure – Loss of Utility

Potential Causes of Overpressure – Loss of Electricity

Electric Motor Driven Equipment Shuts Down

Cooling water pumps

Fans for air-cooled heat exchangers

Compressors

Pumps

Shutdown of pumps and compressors is similar to a blocked outlet



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Potential Causes of Overpressure – Fuel Gas

Fuel Gas

Heaters and boilers shut down

Gas engine and gas turbine driven equipment shut down

Potential Causes of Overpressure – Loss of Instrument Air

Instrument air• Control and shutdown valves move to fail positions

• Pneumatic instruments/controls fail

Fail Open

Fail Closed



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Potential Causes of Overpressure – Loss of Cooling and Heating Medium

Loss of cooling or heating medium

Loss of cooling to condensers• Leads to overpressure because vapor pressure of condensed liquid

increases

Loss of heat input into column reboilers• Leads to overpressure because concentration of high vapor

pressure components in bottoms product increases

Potential Causes of Overpressure – Others

Transient Surge, e.g.

Water/Liquid ‘hammer’

Heat Exchanger tube failure, e.g.

Failure of a heat exchanger tube due to vibration/corrosion

Overpressure of shell-side

Fire, e.g.

Local pool or jet fire causes heat input into vessel resulting inrapid vaporization of liquid in the vessel

Thermal Expansion



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Potential Causes of Overpressure (cont’d)

What are other causes of overpressure? Think about

your own facility and list overpressure events based on:

• Probability of occurrence

• Consequences of a system failure due to overpressure



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Overpressure Protection Options

Fully Rated Design

Facilities designed forcontainment of maximumpressure

Often not practical from acost point of view

Overpressure ProtectionSystems

Pressure relief valves /rupture discs (mechanical)

High Integrity PressureProtection Systems(HIPPS) (instrumented)

Typical Deepwater GoM Platform

What is the “design pressure” of this facility?



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“Design” Pressure of the Facility Shown in the Previous Process Flow Diagram (PFD)

No single “design” pressure that applies to the entire facility

Design pressure is taken as 110% of maximum operatingpressure

Wide range of “normal operating pressures” that apply for thevarious systems and pieces of equipment shown in the PFD

• There are several design pressures that apply

• Primary significance of design pressure is that it dictates thestrength required of the pressure containing components

• This strength is mainly achieved by the thickness of the steel(or other materials) utilized

– Higher design pressure thicker steel heavier andmore expensive

For convenience and practicality, “standard” pressure classes have been established

Standard pressure classes often correlateto “flange ratings”

Flanges are used in flanged connections

• This includes gaskets and bolting; whichare commonly used in oil and gasfacilities for connecting piping, valves andequipment

• An alternative system to the commonlyused welding and threading connectionsystem

Pressure Classes

Segregating the facility into different

design pressure systems is based

on categorizing the facility into different pressure classes.



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Flanges

Two flange specifications are used: ASME B16.5 and API 6A. API 6A is mostly used for wellheads/Christmas trees

ASME B 16.5 Flange Pressure Ratings

Flanges

ASME ClassPressure rating1

psig bar(g)

150 285 19.7

300 740 51.0

600 1480 102.1

900 2220 153.1

1500 3705 255.5

1Carbon steel, temperature -20 to 100oF (-29 to 38oC)



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Pressure Specification Breaks

Pressure specification breaks occur when a facility issectionalized into different design pressure systems andcomponents

• Pressure specification break is the interface betweensystems with different design pressures

Spec breaks result in the potential for a lower rated systemto be over pressured by flow from a higher rated system

Whenever you see a pressure spec break, you mustconfirm the adequacy of overpressure protection of the

low-pressure side



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Learning Objectives

Classify and discuss the typical causes of overpressure

Identify the overpressure protection options

This section has covered the following learning objectives:



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Pressure Relief Devices

Learning Objectives


Understand the terminology associated with relief systems

Identify the different types of relief devices and theirapplications

Explain allowable built-up back pressure for different PSV types



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Types of Relief Devices – Overview

Maximum Operating Pressure

Maximum pressure expected during system operation

Maximum Allowable Working Pressure (MAWP)

Maximum gauge pressure permissible at the top of a completed vessel in itsoperating position for a designated temperature

Maximum allowable working pressure is the basis for the pressure setting of therelief devices that protect the vessel

Accumulation

Pressure increase over the MAWP of the vessel during discharge through thepressure relief device, expressing in pressure units or as a percent

Maximum allowable accumulations are established by applicable codes foroperating and fire contingencies

Back Pressure

Pressure that exists at the outlet of a relief device as a result of the pressure inthe discharge system

Sum of the superimposed and built-up backpressures Superimposed backpressure is the static pressure at the outlet of a pressure

relief device at the time the device is required to operate Built-up backpressure is the increase in pressure in the discharge header that

develops as a result of flow after the relief valve opens

Set Pressure

Inlet gauge pressure at which the relief valve is set to open under serviceconditions

Simmer

Audible or visible escape of compressible fluid between the seat and disc at aninlet static pressure below the relief valve set pressure

Chatter

Rapid opening and closing of relief valve caused by improper sizing or high inletpressure losses which can damage the valve and cause leakage



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Pressure Level Relationships for Pressure Safety Valves

One reason to add more relief valves is that the relief volume is so large that it needs more

than one valve.

It is possible for other valves to be set at pressures up to 105% of the MAWP. In the case of multiple valves the maximum allowable overpressure is 116%.

Accumulation is a characteristic reference of the pressure vessel side of things and the pressure vessel code.

Overpressure is a characteristic related to the sizing of relief valves.

Pressure Safety Types

There are three major types of Pressure Safety Valves(PSV’s):

• Conventional

• Balanced bellows

• Pilot operated



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Conventional and Balanced-Bellows Relief Valves

Balanced BellowsConventional

CaCapp

StSteemm ( (SSppiinnddllee))

AdAdjjuussttiinngg SSccrreeww

SpSprriinngg VeVenntt((UUnpnplluggeuggedd))BBonneonnett

BeBelllloowwss

DiDisskk

AAddjjuussttiningg RRininggBoBoddyy

NoNozzzzllee

SeSeaattiinngg Su Surrffaaccee

When the pressure below the disk reaches the set pressure, the disk will lift up. It will offset the spring force and the gas will relieve out.

The purpose of the bellows is to negate some of the effects of imposed back pressure.

CaCapp

StSteemm ( (SSppiinnddllee))

AAddjjuussttinging SSccrreeww

SpSprriinngg VeVenntt((PPllugguggeedd))BBonneonnett

SSeeaattiing Sng Suurrffaaccee

DiDisskk

AAddjjuussttiningg RRininggBoBoddyy

NNoozzlzzlee

Pilot-Operated Pressure Relief Valves

Diaphragm TypePiston Type

PiPilloott

OuOuttlleett

InInlleett

DoDommee

PiPissttoonn SeSeaall

UnUnbbaallaanncceeddMoMovivinngg MeMemmbbeerr

(P(Piissttoonn))

SeSeaatt

PiPittoott TTuubbee

DDiiapaphhrragagmm

SoSofftt SeSeaatt

MMaaiinn VVaallvvee

DoDommee((PProrocceessssPPrreessssuurree

VaVallvvee C Clloosseedd))

PPiloilott

PiPittoott TTuubbee

OuOuttlleett

InInlleett



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Pop Action Pilot Operated Valve

RelievingNormal Closed

When the set pressure of a pop action valve is reached, the piston will pop open and 100% flow will be achieved.

Modulating Pilot Operated Valve

Partially Open (Modulating)Closed

This valve will not pop open when the set pressure is reached. Instead, it will modulate or throttle.



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Pilot Operated Relief Valves

Advantages of modulating action valves compared to pop action valves:

Less wasted product for each cycle

Less environmental pollution

Less noise during relief cycle

Less built-up back pressure in relief / flare headersystem due to lower flows

Reduced chatter due to poor inlet piping design



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Advantages Disadvantages

Wide range of materials High temp version available Lowest cost

Prone to leakage (if not soft seat) Long simmer/flow period Vulnerable to effects of inlet

pressure loss Sensitive to backpressure

Balanced Bellow Relief Valves


Less sensitivity to back pressure Wide range of materials High temp version available

Prone to leakage (if not soft seat) Long simmer/flow period Vulnerable to effects of inlet

pressure loss Limited bellows life Higher maintenance costs

The failure of bellows in relief valves is a major concern. If the bellows fail, it means that the pressure in the relief header downstream of the valve is going to be inside the bellows providing extra force on areas of the valve that add to the spring force trying to keep the valve closed. If the bellows have failed, the valve is no longer balanced and is now subject to the backpressure effect. We have accepted a higher back pressure because of the bellows. If the bellows has failed and the bonnet is not vented, we have converted the bellows valve to a conventional valve. If the back pressure exceeds 10%, we can expect it to affect the pressure at which the relief valve will lift. If the bellows has failed and the bonnet is vented, we will have some flare gas being released to the atmosphere.

Pilot Operated Relief Valves


Smaller and lighter than other valves Higher pressure ratings in large sizes Good seat tightness before opening

and after reclosing Easier maintenance Easily testable on-site, in service Not affected by back pressures so far

as opening is concerned, but BPover 50% will reduce the flow rate

Dirty service limitations Limited chemical / high temp

compatibility when soft-seat ando-ring piston seals are used

Overview – Pros and Cons

Conventional Relief Valves



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Allowable Built-up Back Pressures for Different PSV Types

Conventional:< 10%

* Flow rate reducedwhen back pressure> ~50% of relievingpressure

Balanced Bellows:< 40%

Pilot Operated:Not affected*



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Protection Design

API RP 520 Part 1 / ISO 23251:2006 covers sizing of:

Mechanical pressure relief valves for all services, except processupsets such as runaway reactions

Rupture discs for all services

API RP 520 Part 2 / ISO 4126-9:2008 cover installation of the mechanical relief devices.

ASME Boiler and Pressure Vessel Code (BPVC), Section I, PowerBoilers and Section VIII, Pressure Vessels cover pressureprotection requirements for fired equipment

ASME PTC25-2008 covers in-service flow capacity and benchtesting under various inlet conditions and fluids



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• Determine applicable relief scenarios

• Calculate relieving loads for all applicable scenarios

• Identifying governing relief case

• Determine if relief is single phase or two phase

• Use appropriate procedures from API RP 520 Part 1/ISO 23251:2006 tocalculate the required orifice sized for the relief valve

• Select a relief valve with the next higher sized orifice from the table ofstandard sizes

• Calculate the actual relieving rate through the selected relief valve

• Estimate inlet pressure loss and backpressure at the actual relieving rateconditions

• Select the appropriate type of pressure relief valve

Relief Valve Selection and Sizing

API Relief Valve Sizes

The outlet pressure rating is typically

the 150 ASME class because these are

low pressure systems.



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Overpressure Protection – Design and Installation Considerations

Calculate relieving temperature, particularly if low due toJoule-Thompson effect (material selection issues)

Inlet pressure drop and back pressure limits (API 520)

Location of the device on the equipment; if it cannot be installed on theequipment, then installation of pilot operated valve should beconsidered

Sparing of pressure relief valves for maintenance; changeover ofpressure relief valves must not leave the equipment in serviceunprotected at any time

Always use full bore valves for isolation of relief devices

In corrosive or fouling services, a rupture disc is often installedupstream of the relief valve to protect the relief valve

Relief valves that are in service must have the isolation valves lockedor car sealed open; spare relief valves must have the isolation valveslocked or car sealed closed



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Relief Valve Installation

Below are two schematics of relief valve installations.

Typical Pressure Relief Valve Without a Stop Valve

Typical Pressure Relief Valve With a Stop Valve



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Pressure Relief Devices

Additional Devices

The use of Ruptured Disk and Buckling Pin are uncommon pressure relieving devices.

Disadvantages

These devices do not re-close. Once ruptured and open, they stay open until the upstream equipment has been de-pressured down to zero. There are some cases where this is okay.

This type of equipment is fast acting but generally their application is very limited.

Rupture disks are occasionally used on the shell side of an exchanger that has very high pressure gas in the tubes. This protects the shell from overpressure due to tube rupture.



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Rupture disks are common in thedownstream industry but are notcommon in the upstream andmidstream industry.

These disks can be installedunderneath a relief valve.

The primary purpose to place arupture disk underneath a reliefvalve is to protect the relief valvefrom highly corrosive or foulingfluids.

If a rupture disc is used beneath arelief valve, be sure to specify anon-fragmenting design so that themetal fragments do not damage therelief valve.

The two illustrations below illustrate an open and a closed Buckling Pin Valve.

Device Details



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High Integrity Pressure Protection Systems HIPPS

Conventional

HIPPS

HIPPS

Why HIPPS?

Less cost for large relief flow applications smallerrelief / flare system

Less flaring reduced emissions

Why not HIPPS?

Complexity

Ongoing maintenance and testing requirements tomaintain / confirm integrity



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Learning Objectives

Understand the terminology associated with relief systems

Identify the different types of relief devices and their applications

Explain allowable built-up back pressure for different PSV types




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Depressurization

Learning Objectives

This section will cover the following learning objective:

Describe the purpose and operation of a depressurizationsystem



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During depressurization, the inlet and outlets (both gas and liquid) are closed.The depressurizing valve is opened and the gas of the vessel is evacuated via aRestriction Orifice (RO) or fixed choke to a safe location, normally a flare or ventsystem.

Depressurization is often done using a control valve.

Depressurization and blowdown are often used interchangeably.

Blowdown

Strictly only applicable to cases where the liquid contents are removed from thevessel.

Normally, main equipment items in a plant are depressurized during anemergency.o Including separation vessels, heat exchangers, distillation columns and

compressors.

Plant emergency depressurization systems reduce the risk of escalation in caseof a fire or a leak of explosive or toxic gas.

Terminology

Depressurization



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Questions

What is vessel depressurization and blowdown?

What are the key design decisions fordepressurizing systems?

??



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Emergency Depressurization / Blowdown

Primary Purpose

To minimize the potential forvessel failure due tooverheating caused by fire

Secondary Purpose

Mitigate consequences of aleak by reducing leakagerate and/or vessel inventoryof flammable materials

Design Criteria (API 521)

Reduce pressure to 50% ofdesign pressure or 100 psig(690 kPa) in 15 minutes

Effect of Depressurizing During a Fire

Time

Ves

sel

wal

l str

ess

leve

l

Ves

sel

wal

l max

tem

per

atu

re

Temperature

Vessel wall stress- no depressurizing

Vessel wall stress- with depressurizing

Vessel wall stress- ultimate tensile strength

Time to failure

Rupture



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Key Design Decisions

The primary design decisions for depressurizingsystems include:

A number of modeling tools are available to help the engineer to

estimate depressurizing performance.

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At what rate must gas be released from each equipment item to meet the required depressurizing times (so what total flare capacity is required)?

What is the lowest metal temperature experienced in each equipment item and in the flare system (which low-temperature materials are necessary)?

What size Restriction Orifice (RO) or other rate controlling device and flare connections are required for depressurizing each section of plant?

Blowdown Valve and Restriction Orifice

Chemical & Process Technology



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Processing facilities are typically “sectionalized” intosmaller areas by automatic shutdown valves basedon identified credible hazard scenarios

• Results in more manageable fire protection system designs,including blowdown flows

If blowdown flows to the flare system are still toolarge, a staggered blowdown strategy can sometimesbe implemented open blowdown valves insequence, not all at once

Emergency Depressurizing / Blowdown

Learning Objectives

This section has covered the following learning objective:

Describe the purpose and operation of a depressurization system



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Emergency Isolation and Depressuring Exercise

Question 1

The separation train is part of a much larger integrated oil and gas facility. It is permanently manned and has a trained emergency response team, and uses a staged blowdown logic for sitewide depressuring. A control loop, such as that which includes the control valve between the HP and IP separators, has an industry typical failure rate of once in ten years. The loop includes everything from the sensor to the trim inside the control valve; everything that may prevent the valve from moving appropriately given a change in level. Choose all applicable answers.

a) Add an emergency isolation valvebetween the HP and IP separators

b) Add a second relief valve at 105%of MAWP to the IP separator

c) Add depressuring valves to allthree separators, in parallel withthe relief valves

d) Add a depressuring valve to theHP separator only, in parallel withthe relief valve

e) Add high capacity rupture discs setat 121% of MAWP in parallel with therelief valves on all three separators

f) Add a deluge systemg) Do nothing, the risk is acceptableh) Add an emergency isolation valve

either upstream or downstream ofthe pump



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Question 1 - Discussion

The separation train is part of a much larger integrated oil and gas facility. It is permanently manned and has a trained emergency response team, and uses a staged blowdown logic for sitewide depressuring. A control loop, such as that which includes the control valve between the HP and IP separators, has an industry typical failure rate of once in ten years. The loop includes everything from the sensor to the trim inside the control valve; everything that may prevent the valve from moving appropriately given a change in level. Choose all applicable answers.

a) Add an emergency isolation valvebetween the HP and IP separators

b) Add a second relief valve at 105%of MAWP to the IP separator

c) Add depressuring valves to allthree separators, in parallel withthe relief valves

d) Add a depressuring valve to theHP separator only, in parallel withthe relief valve

e) Add high capacity rupture discs setat 121% of MAWP in parallel with therelief valves on all three separators

f) Add a deluge systemg) Do nothing, the risk is acceptableh) Add an emergency isolation valve

either upstream or downstream ofthe pump

Question 2

Would your answer be different if the separation train was part of a small, remote, upstream facility with no emergency response capability and no significant offsite safety or environmental risk?

Why?

a) Yesb) No

a) Much lower risk, so insufficient justification for the upgrade. Isolate andabandon.

b) The system as is could rupture in a fire, placing anyone who has notevacuated at risk and exposing the company to bad publicity.



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Question 2 - Discussion

Would your answer be different if the separation train was part of a small, remote, upstream facility with no emergency response capability and no significant offsite safety or environmental risk?

Why?

a) Yesb) No

a) Much lower risk, so insufficient justification for the upgrade. Isolate andabandon.

b) The system as is could rupture in a fire, placing anyone who has notevacuated at risk and exposing the company to bad publicity.



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Flare Systems

Learning Objectives


Identify major components of a flare system and describe theirpurpose

Classify and discuss the different flare ignition methods

Compare the flare tips and their characteristics



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Typical Flare System

Also common to have

segregated HP and LP

systems

Typical Elevated Flare Installation



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Sizing Methodology/Criteria

• Identify relief/blowdown scenarios

• Determine relief loads

• Determine allowable built-up back pressures: PSV set point andPSV type

• Normally limit velocity to < 0.5 Mach

• Hand methods available but typically specialized software isused

Segregation

• Separating flare headers into HP and LP services can reduceheader sizes and cost

• May also segregate the acid gas flare

• Typical pressure break points:

HP relief sources with pressures > 300 psig (20 barg)LP relief sources with pressures < 300 psig (20 barg)

*May also segregate low temp services

Flare Header



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Used to prevent liquid in the relieving/vent stream gas from reachingthe flare stack and tip

Prevent “burning rain” Prevent flame extinguishment, e.g. water carryover Minimize combustion instability/smoke formation Horizontal and vertical vessels used Normally don’t have mist extractors Typically sized for removal of 300–600 micron liquid drops Liquid hold-up requirements (examples only, actual designs must be

considered case-by-case):Max relief load for 90 seconds One well for 15 minutes (offshore)

Seal Drums

Purpose

Flash back protection Maintains slight positive back

pressure on upstream relief/flareheader system

Commonly used in refineries Not so common in upstream E&P

facilities

Knockout Drums

Water Seals (Liquid Seals) provide a positive means of flash-back prevention in addition to enabling the upstream flare system header to operate at a slight positive pressure at all times. This is especially of use when an elevated flare is used in combination with another flare or with a flare gas recovery system.

The water seal vessel is fitted with a special saw-tooth dip leg and anti-pulsation baffle to minimize pulsing. Within the water seal, the water level is preferably maintained by a constant overflow weir in combination with a suitable 'S' bend drainpipe. Filling rates will be sufficient to re-establish the seal within 5 minutes if the liquid seal is broken. Vessel may be equipped with an internal steam coil/sparger for winterization purposes as required.



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Purge Gas

Oxygen-free gas introduced to the flare header/stack to providesufficient flow to prevent air entry from the tip of the flare stack

Typically need ~ 0.05–0.1 ft/sec (0.015–0.03 m/s) velocity (minimum)up stack using methane

May need higher purge rates/velocities to prevent burn-back tipdamage, depending on the tip design

Inverted Gas Seal (Molecular Seal)

Vmin ~ 0.01 ft/sec (0.003 m/s) The stack comes in from the bottom, gas comes up, reverses, flows down, reverses again and flows up. This works because the air will have a significantly higher molecular weight than any credible purge gas. Air molecular weight is about 29 and methane molecular weight is about 16. The heavier molecules are going to be trapped at the base of the seal, unable to rise against the purge gas flow and re-enter the flare stack. Keeping the inverted gas seal free of trouble causing liquid and solid level builds makes the drain very important. It prevents water accumulation and in some places sand accumulation.

Velocity Seal (Fluidic Tip)

Vmin ~ 0.04 ft/sec (0.012 m/s) The purge gas will accelerate, decelerate, and accelerate again as it works its way up the stack of truncated cones. The air will unsuccessfully try to migrate down the stack through the seal because it is met by relatively high velocity gas coming out.



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Flare Ignition Methods

Flame front generator

Electric spark

Pellet/striker plate

Flare gun

Burning arrows

Burning rag

Electric Spark Igniter

High energy/voltagespark at the pilot tip

Ignition of pilot

Allows rapid ignition



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Flame Front Generator

Small fireball sent through1 in. [25.4 mm] ignition line

Compressed air required

Pilots can be lit from grade upto 1 mile [1.61 km] away

Ballistic Pellet Ignition System

Ignition pellets

Pellet launch via guide pipeusing compressed air

High spark generation at tip

Can eliminate the need forconventional pilots

Automatic Pellet

Launcher

Guide pipe

FS‐130 Ignition Pellet



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Flare Stack Sizing

When looking at the variables and the logic behind sizing, usually the dominant factor is ground level thermal radiation at the distance of interest, represented by the distance “R”. Other factors such as ground level sulfur dioxide concentrations can be significant, however ground level thermal radiation dominates the stack height.

A simplifying assumption is that energy is emitted from the mid-point of a flame. When sizing, the height of the stack and one-half the length of the flame defines the midpoint that we will use as the source of the radiated energy. This will enable us by Pythagoras’ Theorem, (right angle triangle, so square the hypotenuse equals the sum of squares of the other two sides) to calculate “D”, the distance the thermal radiation would have to travel before it reaches the point of interest.



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Design Radiation Levels

Allowance is made for solar radiation, plus the heat that is being radiated from the flare itself. Either kilowatts per square meter or Btu per hour per square foot tells how much thermal radiation is tolerable. We would probably put the fence at the distance corresponding to safe continuous exposure. A second fence may be installed, often at the distance corresponding to safe one minute exposure with normal PPE (personal protective equipment). Anyone working in the area would still have time for safe escape.

A safe exit from the area of a flare is needed. This can be critically important, particularly for an off-shore facility where the evacuation routes from the platform might be affected by flare radiation.



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Flare Tip Comparison

What is the jurisdiction? What are the local rules? What do applicable utilities cost? Is weight a significant variable?Can relatively high thermal emissions be compensated for with a higher stack?



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Flare Types – Conventional

Pipe Flare Components

Pipe Pilot Ignition line Lifting lugs Gas seal Flame retention Burner

assemblies

The example is using ANSI 150 flanges, a common choice. Depending on the pressure, this could vary.


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Pipe Flare with Water Spray

Designed with a spray nozzle. The water inlet is at the bottom and a pipe connects the

spray nozzles at the top.

With a flame, water would be quickly vaporized as steam and provide a useful lift.



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Flare Types – Coanda

A common specialist tip is the Coanda design or ’tulip’.

Low pressure gas comes up through the middle.

High pressure gas comes up through the annulus.

Coming out around the outside of the tip there will be a slot. At relatively high velocity

gas, air will draw in with it.

The flame will be initiated at just above the base of the tulip, resulting in effective

ignition.



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In more detail, high pressure gas is coming up around the annulus exiting through the slot, therefore, the tulip profile. A gas film will be seen at a low-pressure region developing between the gas film and the tulip that will draw the gas in next to the tulip, air being drawn in and a viable mixture reaching the top of the tulip.



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Flare Types – Birwelco

This is the Sonajet design from Birwelco. There is low pressure in the middle, high pressure tubes around the periphery, and a windshield.

When in service, several small flames are seen.



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Ground Flare Installation

A ground flare is where the combustion takes place at ground level. It varies in complexity, and may consist either of conventional flare burners discharging horizontally with:

Low visibility/low noise design Short flame length Open pit/totally enclosed designs

The type is the multijet flare (enclosed type). Compared to elevated flares, ground flares can achieve smokeless operation as well. They can be fairly quiet because the flow is split among multiple small burners and are much less visible than an elevated flare. However, they have poor dispersion of combustion product because the stack is near to ground; which may result in severe air pollution or hazard if the combustion products are toxic or in the event of flame-out.



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Hazards and Limitations

Loss of flame/pilot Operation without an operating flare causes a serious and unsafe situation.

Liquid carryover Burning rain results in a number of fires around the flare. If water, the flame could be extinguished, or with two phase flow the capacity can be restricted.

Flashback – air intrusion Guard against flashback with a velocity seal, a molecular seal or with the water seal down at the base of the stack.

Loss or insufficient purge If there is less than adequate purge, then there is a significantly higher probability of air intrusion

Steam control under/over Care must be taken in regards to flow rate and ensuring that there is neither too much nor too little.

Freezing condensate in cold climates

To avoid possible freezing in the knockout drum, include a heater.

Inconsistent composition, pressure and temperature

Flares have to be designed as such that they will be robust and variation tolerant to the credible range of compositions, pressures and temperatures that it they may see.

Brittle fracture of material for cold relief

If a cold relief is going to be done, or have significant cooling due to Joule-Thomson, it must be done safely.

Blockage Blockage due to hydrate formation has occurred on several occasions. Don’t mix a cold flare with a wet flare.

Noise and light Depending on the location of the facility, noise and light may be a significant factor in terms of local regulation and community relations.

Thermal Radiation This is usually the governing factor in determining the height of the flare. In the maximum relief case, we ensure that a threat is not imposed on people, facilities or neighbors.



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Smokeless Flaring

Smoke is caused by incomplete combustion which results in soot (carbon) formation. There are three main methods for achieving smokeless flaring:

High Pressure Tip Large flared gas pressure drop across the tip generates a high degree of turbulence and air mixing, increasing combustion efficiency

Steam Injection at the Tip Injected steam inspirates air into the combustion zone, improving mixing and combustion efficiency

Air Assist A blower located at grade level supplies air to the tip to promote air-fuel mixing and improved combustion efficiency



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There is a normally closed pressure control valve in the header betweenthe knockout drum and the flare stack.

The flare gas recovery line goes through a cooler, into a separator. Thegas is compressed and returned to any convenient point in the process.

The liquids are returned to the flare knockout drum, where they will berecovered along with any other liquids that drop out in the drum.

There will be a bypass line to enable quick and reliable opening of thecontrol valve. The bypass line will have a rupture disc or a relief valve.

These alternatives involve additional maintenance, additional cost, andadditional opportunities for failure.

For low pressure applications, a liquid seal drum should be consideredas it is simpler and often less expensive.

Flare Gas Recovery

A flare gas recovery system is designed to recover flare gas under normal operations not under emergency flaring. A common way of doing this is shown in the following image.



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Flare Gas Recovery System

The flare gas comes into a knockout drum, the header goes to a liquid seal drum, and from there connects into the flare stack. The flare gas recovery line goes to a compressor. This example shows a liquid ring compressor. That may be used for small streams. For larger streams, it may be a reciprocating compressor or a screw compressor. The gas will go to a three-phase separator where liquid hydrocarbon or water will be removed, and the gas will go to flare gas recovery. The compressor will need a recycle line which will bring the gas back into the suction.



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This example is using the pellet ignition system. Shown is the launcher and launch tube. The pellet will strike the striker plate providing a shower of high energy sparks, igniting the flare gas at the end of the flare boom.

Flare Gas Recovery with Ballistic Pellet Ignition

The image below shows flare gas recovery, a flare, and ignitor. At the bottom left, the flare header is shown coming into the knock-out drum. A line leaving the knock-out drum goes to the flare gas recovery compressor. The line on the right is the flare header. The main valve is shown closed with a rupture disk in a bypass line. In case of a genuine flaring emergency, the disk would burst and the gas would flow to flare.



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Learning Objectives

Identify major components of a flare system and describe theirpurpose

Classify and discuss the different flare ignition methods

Compare the flare tips and their characteristics


Back to Work Suggestions


Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.

RReeview your view your ffllarare header as-built eleve header as-built elevations.ations.

Is Is itit self self-dr-draaining ining to tto thhe dre drum?um? IIff nonott,, how how is is drdrainaainage handlege handled? d?

AArre e ssuuititable able manamanagementgement systems in systems in plplaacce to e to ggiive ve yyoou confu confidence idence tthhaatt dr drainaainage ge wwiill ll bbee aaddeeqquauate te in in an emergencan emergency?y?

Check your fCheck your fllaarre e drum desdrum desiign.gn.

WWhhaatt is is tthhe desige designn basis? basis?

Is Is therthere ane anyytthing hing thathatt can can pluplugg up or up or blow blow out? out?

HHaavvee ther there be beeen en changes in changes in ffeeeedd r raate, te, compcomposition, osition, or or opopereraatting ing conditconditions tions thhaatt could rcould reequirquire a e a rreevviieeww of the of the aaddeeqquauaccyy of the fof the fllarare e drdrum? um?

TThherere should be should bee MOMOCs Cs in in plplaacce to e to answanswer thaer thatt, , butbut it it is is nonott unkunknnown own ffoor r severseveraal l small small cchhanges anges to to aadd up to dd up to ssoomemetthhing ing sigsignnifificicantant..



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PetroAcademyTM Process Safety Engineering Skill Modules

Process Safety Risk Analysis and Inherently Safer Design Core

Process Hazards Analysis and Layers of Protection Analysis Core

Leakage and Dispersion of Hydrocarbons Core

Combustion Behavior of Hydrocarbons Core

Sources of Ignition and Hazardous Area Classification Core

Specific Plant Systems and Equipment Core


Historical Incident Databases, Plant Layout and Equipment Spacing Core

SIS, Monitoring and Control Core

Fire Protection Systems Core

Back to Work Suggestions


Leverage the skills you’ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided.

Field check Field check at least one sub at least one sub header and header and thethemainmain flar flare heade headerer; ; chochooosse a e a susubb head header er withwithaass much elev much elevaattion ion difference difference aass you you cacan findn findanandd access. access.

ArAre e therthere ane any diffy differerences ences bbeetwtweeeen the n the drdraawwing ing and rand reealitality?y?



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Documents

Why This Module Is Important - Active Learnercloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/PRS-RFS/PRS-RFS-1.pdfHeating and Cooling Medium Potential Causes of