1. Overpressure Scenarios
and
Required Relief Rates
PART I

2. Required Data
• Procure latest PIDs
• Heat and Mass Balance Report
• Rotating Equipment Datasheet (performance curves,
etc.)
• Vessel and Heat Exchanger Datasheets (drawings)
• Operating/Emergency procedures
• Review current project specific document-Relief &
Blowdown Philosophy

3. Overpressure Scenario Identification
• Start with PIDs and PFDs
• Analyze on equipment-by-equipment basis
• Typically start at front end of process
• Identify sources of feed & its maximum pressure
• Identify all heat input sources including external fire
• No credit for favorable instrument or operator response
• Include comments to explain rationale

4. Industry Guidelines
• API RP 521
• API 2000
• Project Specific Guidelines

5. API RP 521
1. Fire
2. Closed outlets (Vapor BO or Liquid BO)
3. Failure Opening/closing of Control Valve
4. Thermal Expansion
5. Tube rupture
6. Check Valve Leakage
7. Reflux failure
8. Abnormal heat input
9. Power Failure
10. Utility failure (CW+IA+FG+Steam)

6. External Fire
Causes:
1.Explosion caused by the ignition of a flammable
leaking gas
2. Leakage of flammable hydrocarbon inventory

7. Applicability Guidelines
• Equipment must be located with in a fire zone
• Some portion of the equipment must be located below the
maximum fire height (API RP 521 uses 25 feet)
• In some cases, the time required to reach relief pressure
may render the scenario not credible

8. Sizing Equation-
Q=21000*F*A^0.82 (Btu/hr)
Q=34500*F*A^0.82 (Btu/hr)
Wetted Surface Area-
• Liquid full such as Treaters: 100%
• Surge Drums, KO drums, Process vessels: NLL
• Fractionating Columns: NLL + Hold up
• Working storage (MAWP >15 psig): Max level up to 25 ft
• Spheres: Up to max horizontal diameter or 25 ft whichever
is greater
Heat Of Vaporization-Latent heats will be based on the heat
required to vaporize the first 10% by mass.
Q = m * Hv@ relief

9. Shell and Tube Exchangers
• Individual exchangers often not individually protected for
fire
• Often rely on downstream vessels for protection
• If downstream relief is used, check if loads should be
additive (e.g., exchanger and vessel are in same fire zone)
• Shell side and tube side may be treated differently (many
companies neglect tube side due to small surface area)

10. Air Coolers
• Condensing versus liquid cooling services may be treated
differently (see API RP 521 Section 3.15.7)
• Many air coolers are located above the maximum fire height
• API has special equations for air coolers
• Exact treatment of fire case for air coolers should be
defined in the Project Guidelines

11. Filters, Strainers, etc.
• Equipment less than 24” OD is exempt from ASME VIII (and
typically fire relief requirement)
• Many companies have additional exclusions for small filters
• Equipment fabricated from pipe may be treated differently
than ASME stamped equipment
• Often rely on downstream equipment for relief – check
Project Guidelines on rules to use

12. Inlet Control Valve Failure:-
Causes-
Instrumentation failure may occur due to
-Transmission signal failure
-Process Measuring element failure
Mechanical failure may occur due to
-Stem breakage
-Plug jamming
-Misoperation
May result in control valve opening or to move in
opposite direction of its design failure position.

13. Determining Applicability
• Trace all inlet lines to vessel to identify inlet control devices
• Trace upstream from any control devices to determine
maximum expected upstream pressure
• Upstream pressure will be normal or maximum operating
pressure
• Can selected upstream pressure exceed downstream
equipment design pressure?
• Consider relative vessel volumes when the upstream
volume is much less than the downstream volume

14. Glycol Contactor Glycol Flash Tank
PSV-1 Dry Gas
@ 750 psig HC Vapors
200 psig
Lean Glycol
Vapor Vapor
Wet Gas LC
675 psig Liquid
LC
Liquid
LV LV
Rich Glycol

15. Glycol Contactor Glycol Flash Tank
PSV-1 Dry Gas
@ 750 psig HC Vapors
200 psig
Lean Glycol
Vapor Vapor
Wet Gas LC
675 psig Liquid
Fails
LC
Liquid Open
LV LV
Rich Glycol

16. Glycol Contactor Glycol Flash Tank
PSV-1 Dry Gas
@ 750 psig HC Vapors
200 psig
Lean Glycol
Vapor Vapor
Wet Gas LC
675 psig Liquid
Fails
LC
Liquid Open
LV LV
Rich Glycol

17. API RP 521 Section 3.10.3
“The scenario to consider is that one inlet valve will be in a
fully opened position regardless of the control valve failure
position…. Therefore, the required relief capacity is the
difference between the maximum expected inlet flow and
the normal outlet flow adjusted for relieving conditions and
considering unit turndown…”

18. Determining Required Relief Rate
• Use control valve manufacturer’s calculations
• Determine valve flow coefficients
• Consider partially or fully open bypass
• Calculate flow across control valve at downstream relief
pressure
• Take credit for normal outflow in volumetric terms

19. Gas Blowby – Special Considerations
Potential for Two Phase Relief in Downstream Vessel
• Perform relative inventory check to determine how much
downstream vessel will fill
• Assume downstream level control remains in normal
position
Relief behavior depends on liquid level
- Below inlet nozzle → all vapor relief
- Between inlet nozzle and full, perform disengagement
calculation → vapor or two phase
- Full → liquid displacement equal to volume of
incoming vapor

20. Check Downstream Fill Level
Overfill – Liquid
Displacement
Potential
Two Phase
Vapor
Inlet from
LC Valve
All Vapor
Venting
LC
Normal
Level
LV

21. Gas Blowby – Special Considerations
Calculating Flow Across Level Control Valve
• Consider assuming two phase flow across valve to reduce
relief requirement

22. Heat Exchanger
Tube Rupture
Causes:
- Vibration, corrosion, erosion, thermal shock, differential
shell side to tube side expansion (fixed tube sheet
exchanger), brittle fracture potential, tube to baffle chafing,
degradation of tubes and tube sheets.

24. High Pressure
Low Pressure

25. High Pressure
Low Pressure
Corrosion of Tube

26. High Pressure
Low Pressure
Corrosion of Tube
Pinhole Leak

27. High Pressure
Low Pressure
Corrosion of Tube
Tube Failure

28. Low Pressure on Tube Side
Low Pressure
High Pressure
Corrosion of Tube
Tube Failure

29. Determining Applicability
1. Determine maximum high-pressure side pressure (Phi)
- Design Pressure
- relief device set pressure
- other mechanical limitation
2. Determine low-pressure side test pressure along with
associated equipment and piping (Plow)
• Compare the two pressures
- If (Phi) > (Plow) then tube rupture relief is required
Not generally applied to double pipe exchangers or other
types of exchangers with schedule pipe for tubes

30. API 521 Section 3.18.3
The required rate is determined assuming:
• Single tube has been broken down.
• The high-pressure side fluid is assumed to flow through the
broken tube.
• This is often simplified by conservatively estimating the flow rate
based on two orifices/one orifice.
• If there is flash across the broken tube then two phase flow
needs to consider.
• Use Crane’s equations based on maximum pressure on high
pressure side and relief pressure on low side.

31. Additional Considerations
• Relief fluid properties are generally not the same as those
upstream of the tube rupture:
- Flashing across tube rupture
- Heating due to contact with hot side fluid
- Displacement of low-pressure side fluid
• For high pressure differentials, dynamic analysis is
sometimes applied

32. Blocked Outlet (Vapor Or Liquid)
Causes-
Instrumentation System failure may occur
-Transmission signal failure
-Process Measuring element failure
Mechanical failure may occur due to
-Stem breakage
-Plug jamming
-Manual valve mal operation
May result in control valve/block valve to move in
closed position.

33. Determining Applicability For Blocked Vapor
• Identify potential mechanism resulting in blockage
• Identify sources of overpressure include compressors,
high-pressure supply headers, and process heat

34. Flash Drum-Blocked Vapor
PSV-1 Dry Gas
@ 200 psig
Fails
Close
HC Liquid
250 psig Vapor
CV
LC
Liquid
LV

35. Determining Applicability For Blocked
Liquid
• Identify potential mechanism resulting in blockage
• Identify sources of overpressure include pumps, high-
pressure supply headers.
• Adequate indication and response time may render
overfilling not credible
- Independent high level alarm
- 20 minutes of retention after alarm prior to overfill
• Often not considered for columns and vessels with no
normal liquid inflow (suction scrubbers, etc.)

36. Flash Drum-Blocked Liquid
PSV-1 Dry Gas
@ 200 psig
HC Liquid
250 psig Vapor
CV Fails
LC Close
Liquid
LV

37. Required Relief Rates
• Centrifugal pumps and compressors
- Performance curves define flow at relief
• PD pumps
- Use design flow rate
• Reciprocating compressors
- Use reduced volumetric efficiency
• High pressure supply headers
- Normal inlet flow

38. Thermal Expansion

39. Causes:
“Hydraulic expansion … can result from several causes, the most
common of which are the following:
a. An exchanger is blocked-in on the cold side with flow in the
hot side.
b. Piping or vessels are blocked-in while they are filled with cold
liquid and are subsequently heated by heat tracing, coils, ambient
heat gain, solar radiation or fire.

40. Heat Exchanger Thermal Expansion
o
90 F
o
Cold Side 120 F
Hot Side
o o
220 F 110 F

41. Cold Side Inadvertently
Blocked Prior to Hot Side
o
90 F
o
Cold Side 120 F
Hot Side
o o
220 F 110 F

42. Cold Side Temperature Increases
o
170 F
Cold Side
Hot Side
q=(Cubic Expansion
o
Coeff.*Q)/ 220 F
(1000*sp.gravity*specific
heat capacity)

43. Is a relief device required?
• Guidelines on piping from, “Decide Whether to Use Thermal
Relief Valves,” CEP 12/93; Bravo and Beatty
- Yes, for lines more than 80 feet long
- No, for lines with an ID less than 1.5”
- No, for lines with high operating temperatures
• API RP 521 on exchangers
- Locking open a block valve and posting signs may be
adequate protection

44. Check Valve Leakage
Causes-
-Stuck Open
-Broken flapper
-Check valve seat leakage
May result in overpressure due to leakage through check valve
if the maximum normal operating pressure of the high-
pressure system is greater than the design pressure of vessels
present upstream of the check valve.

45. Check Valve Leakage
- Leakage rate can be assumed equal to the 10% of the
maximum normal forward flow (vapor or liquid).
-The reverse flow rate through a single check valve can be
determined using the normal flow characteristics (i.e.,
forward-flow Cv) of the check valve. Leakage rate can be
assumed to be 10 % forward flow Cv.

46. Overhead Condenser
Failure, Reflux Failure, Abnormal Heat Input
Or Power Failure
Causes-
Utility Failure, Mechanical failure of rotary equipments, Shutting down
of utility compressor, Failure opening of control valve, Pumps or fail
closure of control valve on supply line may result in complete loss of a
utility or the partial loss of a utility, Instrumentation failure or loss of
transformer/MCC/Busbar

47. Condenser
PC
Overhead (V)
Reflux (R)
Accumulator
LC
Feed (F)
Reboiler
Column
Heat in (Q) LC
Bottoms (B)

48. Loss of Coolant
Condenser to Condenser
PC
Overhead (V)
Reflux (R)
Accumulator
LC
Feed (F)
Reboiler
Column
Heat in (Q) LC
Bottoms (B)

49. Loss of
Reflux Condenser
PC
Overhead (V)
Reflux (R)
Accumulator
LC
Feed (F)
Process
Reboiler
Column
LC Steam
Heat in (Q)
Bottoms (B)

50. Determining Applicability
• In general, loss of cooling (from condenser or pump-around
exchanger) will result in overpressure for distillation
systems
• Loss of reflux can also result in flooding of condenser

51. In Conclusion…
• Collect information required to perform analysis
• Review relevant guidelines
• Determine all overpressure scenarios that apply to each
piece of equipment
• Analyze required relief rates using standard methods
• Be conservative at first

52. Thank You