2. OIL & GAS
CONTENT
• INTRODUCTION
• PSV TYPES
• CHATTERING PROBLEM
• SIZING CALCULATION
• EXAMPLE
3. OIL & GAS
INTRODUCTION
• Relief systems are provided on a platform in order to
ensure the safe operation of the facilities.
• In accordance with API RP 14C, all hydrocarbons handling
equipment and pressure vessels will be provided with two
levels of over protection, high pressure trip (PSHH) with
shutdown action, and protection by mechanical devices,
Pressure Safety Valve (PSV) or Rupture Disc.
• PSVs are installed at every point identified as potentially
hazardous, that is, at points where upset conditions
create pressure which may exceed the maximum
allowable working pressure.
4. OIL & GAS
INTRODUCTION
How High Pressure Develop
• Over heating
• High head ( from pumping or compression)
• Over Filling
• Failure of Regulator / Control valve.
• External Fire
• Runaway Reaction
• Combustion of gas/dust
• Freezing
• Thermal Expansion
• Loss of Mixing
• Others
5. OIL & GAS
INTRODUCTION
Definitions
• Operating pressure : The gauge pressure during normal
service.
• Set Pressure : The pressure at which the relief device
begins to activate or open.
• Maximum Allowable Working Pressure (MAWP) : The
maximum guage pressure permissible at the top of a vessel
for a designated temperature.
Vessel fails at 4 to 5 times of MAWP!!!! . But only
hydrostatically tested to 1.5 times.
• Accumulation : The pressure increase over the maximum
allowable working pressure of a vessel during the relief
process. Expressed as % of MAWP.
7. OIL & GAS
Definitions
• Over Pressure : The pressure increase in vessel over the set
pressure during the relieving process. Overpressure is
equivalent to the accumulation when the set pressure is at the
MAWP. Expressed as % of set pressure. Must be specified prior
relief design. Typically 10 % ( or for fire 21%) will be used.
Pressure
Time
Relief begin to open
Set Pressure
Over Pressure
INTRODUCTION
8. OIL & GAS
Definitions
• Blow-down : The pressure difference between the relief
set pressure and the relief reseating pressure.
• Maximum Allowable Accumulated Pressure : The sum of
the maximum allowable working pressure plus the allowable
accumulation.
INTRODUCTION
9. OIL & GAS
INTRODUCTION
Guideline for relief pressures
(Adapted from API RP 520 : “ Sizing, Selection, and Installation of Pressure-Relieving
Devices in Refineries.” , page 3)
10. OIL & GAS
Definitions
• Back Pressure : The pressure at the outlet of the relief
device during the relief process due to pressure in the
discharge system.
1. Superimposed Back Pressure.
2. Built-up Back Pressure.
Total Back Pressure = Superimposed Back Pressure + Built-up Back Pressure
INTRODUCTION
11. OIL & GAS
INTRODUCTION
Definitions
1. Superimposed Back Pressure is the back pressure which
may exist at the outlet of a particular relief valve when connected
to a closed system. The pressure can be constant or variable. The
Superimposed back pressure always exists even when the relief
valve is closed.
2. Built-up Back Pressure is the pressure at the discharge of a
relief device which develops due to the relief flow through the
device when the relief valve opens. The built-up back pressure
depends on the valve itself but also on the design of the relief
piping. It can reach excessive values in the case of vary high
set pressures and/or poorly designed piping with too much pressure
Loss. The built-up back pressure is variable.
12. OIL & GAS
PSV TYPES
General Design of PSV
1. Direct acting type
• Oldest and most common.
• Kept closed by a spring or weight to oppose
lifting force of process pressure.
2. Balanced Bellows.
3. Pilot operated type
• Kept closed by process pressure
4. Modulating Pilot.
13. OIL & GAS
PSV TYPES
The following types of PSV are generally used.
1. Conventional PSV
2. Balanced Type PSV (Balanced Bellow)
3. Pilot Operated PSV
4. Modulating Pilot Operated PSV
5. Thermal PSV
14. OIL & GAS
PSV TYPES
Conventional PSV Advantages
• Most reliable type if properly sized
and operated
• Versatile -- can be used in many services
• Compatible with fouling or dirty service.
Disadvantages
• Relieving pressure affected by
back pressure
• Susceptible to chatter if built-up
back pressure is too high
15. OIL & GAS
Balanced Bellow PSV
PSV TYPES
Advantages
• Relieving pressure not affected by back
pressure.
• Can handle higher built-up back pressure.
• Protects spring from corrosion.
• Wide range of materials available &
chemical compatibility.
Disadvantages
• Bellows susceptible to fatigue/rupture.
• May release flammables/toxics to
atmosphere.
• High maintenance costs.
16. OIL & GAS
Pilot Operated PSV Advantages
• Relieving pressure not affected by
backpressure
• Can operate at up to 98% of set pressure
• Less susceptible to chatter (some models)
Disadvantages
• Pilot is susceptible to plugging (therefore
not recommended for fouling service,
eg. Wax).
• Limited chemical and high temperature
use by “O-ring” seals
• Vapor condensation and liquid
accumulation above the piston may
cause problems
• Potential for back flow
PSV TYPES
17. OIL & GAS
CHATTERING PROBLEM
Modulating Pilot Operated
There are two main types of pilot control operation
• Pop action : Main valve fully open at set pressure
• Modulating : Main valve opens according to relief demand.
Modulating pilots have additional advantages:
• They only open the main valve enough to keep the system at set
pressure which leads to less wasted product being relieved
through the valve.
• Less noise generated by the valve when it is required to relieve.
• Recommended for Wellhead platform PSV.
18. OIL & GAS
CHATTERING PROBLEM
Main valve
piston lift
Pressure
Opening
Closing
100 % Lift
POP Action
19. OIL & GAS
CHATTERING PROBLEM
Main valve
piston lift
Pressure
Opening
Closing
100 % Lift
Modulating
20. OIL & GAS
Chattering Problem
• Chattering is the rapid, alternating opening and closing
of a PSV.
• Resulting vibration may cause misalignment, valve seat
damage and, if prolonged, can cause mechanical failure
of valve internals and associated piping.
• Chatter may occur in either liquid or vapor services
CHATTERING PROBLEM
21. OIL & GAS
Cause of Chattering
• Excessive inlet pressure drop
• Excessive built-up back pressure
• Oversized valve
• Valve handling widely differing rates
CHATTERING PROBLEM
22. OIL & GAS
Excessive inlet pressure drop
• Normal PSV has definite pop
and reseat pressures.
CHATTERING PROBLEM
Reseat or close pressure Pop or opening pressure
Blow-down = Different between pop and reseat pressure
23. OIL & GAS
CHATTERING PROBLEM
Excessive inlet pressure drop : Solution
If you can’t change the
piping
• Install smaller PSV
• Install different type of
PSV
24. OIL & GAS
CHATTERING PROBLEM
Excessive Built-up Back Pressure
Excessive outlet pressure will also cause chatter.
Avoid
• Long outlet piping runs.
• Elbows and turns.
• Sharp edge reductions.
But if you must
• Make outlet piping large!
25. OIL & GAS
CHATTERING PROBLEM
Improper Valve Size
Oversized valve
• Must flow at least 25% of capacity to keep valve open.
• Especially bad in larger sizes.
Valve handling widely differing rates
• Leads to oversized valve case.
26. OIL & GAS
SIZING CALCULATION
Step Of Sizing Calculation
Develop Process Safety Diagram (PSD)
Develop relief scenarios by using general possible cause and PSD
Determine required relief area for each cases (Gas, Liquid, 2-Phases)
Choose the worst case scenario to be a governing case
Select proper orifice and valve body size based on STD
Calculate inlet line size (Line ∆P < 3%of RP)
Perform preliminary estimate of tail pipe
Perform Flare system modeling to indicate total back pressure
and most suitable tail pipe size.
Select PSV type (Conventional, Balanced Bellow, Pilot Operated
27. OIL & GAS
SIZING CALCULATION
Develop Process Safety Diagram (PSD)
Process safety diagram is the diagram which show
all installation of all process safety equipments (PSHH,
TSHH, PSV, BDV, Rupture disc, etc.) intend to be used in
evaluation of all possible relieving scenarios in process
facilities. Process safety diagram must be developed before
performing any PSV calculation.
28. OIL & GAS
SIZING CALCULATION
Develop Process Safety Diagram (PSD)
29. OIL & GAS
SIZING CALCULATION
Develop relief scenarios by using general possible cause and PSD
Equipment
Possible Scenarios
Pump
HEX Line
Vessel /
Column
Compressor
Blocked Outlet
Thermal Expansion
Tube Rupture
Gas Blow-by
Inlet Control Valve Failure
Exterior Fire
Note : Exterior Fire is not applicable for PHEX!!
30. OIL & GAS
SIZING CALCULATION
Blocked Outlet/ Blocked Discharge
CLOSED
CLOSED
CLOSED
CLOSED
CLOSED
Process Vessel
Compressor Pump
This situation arises from the inadvertent closure of a block valve or failure
of a control valve in the closed position on an outlet line. Typical
overpressure application where this form of protection is required includes
production separators, compressor discharge piping or pump discharge
piping. The safety relief valves are sized to handle 100% of the anticipated
upstream flow. If the feed stream(s) is multi-phase, the relief rate is the total
inlet flow (gas plus liquids).
31. OIL & GAS
SIZING CALCULATION
Thermal Expansion/ Thermal Relief
Heat Exchanger
Line
Hot Side
Cold Side
CLOSED
CLOSED CLOSED
Thermal expansion relief valves (TERV’s) are required in liquid-full systems
if the system can be blocked in and/or subjected to heat input from the
atmosphere or process that results in overpressure.
32. OIL & GAS
SIZING CALCULATION
Tube Rupture
Heat Exchanger
Hot Side
Cold Side
OR
Heat Exchanger
Hot Side
Cold Side
Tube rupture causing vapour to enter either the tubeside or shellside
of a heat exchanger will cause a pressure spike to travel through the
fluid at sonic velocity. Generally, a PSV will not lift fast enough to protect
the system. Protection against tube rupture is typically by the use
of bursting discs.
33. OIL & GAS
SIZING CALCULATION
Suddenly Opening
Pressure at PSHH
Liquid at LSLL
Gas blow-by occurs when liquid level in a partially filled vessel drops so
low that gas exits via the liquid outlet nozzle due to level control failure.
Loss of liquid level will result in gas from the high pressure vessel passing
into the low pressure system downstream of the liquid level control valve.
Gas Blow-by
34. OIL & GAS
SIZING CALCULATION
Fail to open
Pressure at normal
Liquid at normal
Inlet Control Valve Failure
The relief rate is equal to the difference between the maximum inlet
flow and the flow, at relief conditions, from the outlet valves that
remain open. No credit for outlet valves response will be taken i.e.
they will be assumed to remain at their normal operating point
(% open).
35. OIL & GAS
SIZING CALCULATION
Exterior Fire
Generally, the production & processing facilities will be segregated into fire
areas, by means of plated decks, fire walls, or edge of the platform. During
a fire in one of the fire areas, all equipment within that area is assumed to be
fully exposed to the fire.
It is assumed that during a fire there is no feed to or product from an
affected system, and all normal heat inputs have ceased.
• No credit will be taken for the presence of any water spray systems.
• No credit will be taken for thermal insulation on vessels.
36. OIL & GAS
SIZING CALCULATION
Pool Fire Jet Fire
Fire Type
Systems with significant liquid
hydrocarbon inventory will be
considered for pool fire case.
Heat flux will be calculated as
per API RP521. Credit for a 40%
reduction in heat flux may be
taken for good drainage and
the presence of prompt fire
fighting efforts as specified in
API RP 521.
Where potential for jet fire exists, relief
load will be calculated for higher heat flux
from heat fire. The heat flux generated by
jet fire ranges from 50 kW/m2 to 300 kW /m2.
However, the net heat flux into the fluid will
depend on many factors such as fuel type,
vessel temperature, the surface emissivity,
the fire environment, the radiative and
convective components of the fire.
37. OIL & GAS
SIZING CALCULATION
Vessel Type & Fluid relief type
Vessel type could be :
• Dry or empty vessel
• Vessels containing liquid -> Need to consider effect of
wetted area of vessel
Fluid relief type could be :
• Fluid is sub-critical: P<0.9*Pc
• Fluid is near its critical pressure: 0.9Pc < P < 1.1*Pc
• Fluid is super critical (dense phase): P > 1.1*Pc
Pc = Critical Pressure
P = Relieving Pressure
38. OIL & GAS
SIZING CALCULATION
Fire case
Jet Fire
Dry Vessel Wetted vessel
Sub Critical Flow
Near Critical Flow
Super Critical Flow
Pool Fire
2 CASES
2 CASES
3 CASES
Totally = 2x2x3 = 12 cases possible
Hence 12 methods of calculation for Fire case
39. OIL & GAS
SIZING CALCULATION
Determine required relief area for each case (Gas, Liquid, 2-Phases)
Target of sizing relief valve
1. Determine the relief rate.
2. Determine the required relief area.
3. Select the standard relief area.
Code and standard required
API RP 520 : “ Sizing, Selection, and Installation of Pressure-Relieving
Devices in Refineries.”
API RP 521 : “ Guide for Pressure Relieving and Depressuring Systems.”
40. OIL & GAS
SIZING CALCULATION
Relief Phase
Single Phase Relief
Two Phase Relief
Vapor Phase Relief
Liquid Phase Relief
Relief Type
Continuous Relief
Transient Relief Thermal Relief
Generally
Gas/Vapor
Steam
Relief fluid category
Determine required relief area for each case (Gas, Liquid, 2-Phases)
41. OIL & GAS
SIZING CALCULATION
• Determine relief rate, some cases (eg. Gas blow-by, tube rupture,
fire case etc.) are very complicated and contain many steps of calculation
especially fire case.
• API RP520/ 521 shows the simple method of calculation in order to
determine the relief rate. This does not govern all relief scenarios. Hence
some companies have developed their own procedure to determine the
relief rate.
Determine required relief area for each case (Gas, Liquid, 2-Phases)
42. OIL & GAS
SIZING CALCULATION
Vapor Phase Relief
• Relief valves for single phase vapour flow will be sized according
to the methodology presented in API RP 520, Section 3 (reference 4).
• The sizing equations fall into 2 categories, depending on whether
flow is critical or subcritical.
• The critical pressure must be checked using the equation below:
)
1
(
1
1
2
.
k
k
cf
k
P
P
where
Pcf = critical flow throat pressure (psia)
P1 = upstream relieving pressure (psia)
k = ratio of specific heats
Ref. API 520 section 3.6.1.4
43. OIL & GAS
SIZING CALCULATION
Vapor Phase Relief
• If flow is critical (Pcf > downstream pressure P2), the critical
sizing equation is used:
A
W
CK P K
TZ
M
d b
1
Ref. API 520 section 3.6.2.1
Where
A = required effective discharge area of the valve ( in2).
W = required flow through the valve (lb/hr).
C = coefficient determined from an expression of the ratio of the specific heats of the gas
or vapour at standard conditions. This can be obtained from Figure 26 or Table 9 in
API 520.
Kd = effective coefficient of discharge = 0.975
P1 = upstream relieving pressure, in psia.
Kb = capacity correction factor due to back-pressure. This can be obtained from the
manufacturer’s literature or estimated from Figure 27 in API 520. The back-pressure
correction factor applies to balanced-bellows valves only.
T = relieving temperature of the inlet gas or vapour, in R.
Z = compressibility factor for the deviation of the actual gas from a perfect gas, a ratio
evaluated at inlet conditions.
M = molecular weight of the gas or vapour.
44. OIL & GAS
SIZING CALCULATION
Vapor Phase Relief
• If flow is subcritical, the following equation will be used:
)
(
.
.
735 2
1
1
2 P
P
P
M
ZT
K
F
W
A
d
Ref. API 520 section 4.3.3.1
Where A = required effective discharge area of the valve, in square inches.
W = required flow through the valve, in pounds per hour.
F2 = coefficient of subcritical flow
=
r
r
r
k
k k
k
k
1
1
)
(
)
1
(
1
2
Ref. API 520 section 4.3.3.1
45. OIL & GAS
SIZING CALCULATION
k = ratio of the specific heats.
r = ratio of back pressure to upstream relieving pressure, P2 /P1.
Kd = effective coefficient of discharge = 0.975
Z = compressibility at relieving inlet conditions.
T = relieving temperature of the inlet gas or vapour (R)
M = molecular weight of the gas or vapour.
P1 & P2 = upstream relieving pressure and back-pressure pressure respectively (psia)
Vapor Phase Relief
46. OIL & GAS
SIZING CALCULATION
Vapor Phase Relief
• Relief valves in steam service will be sized as follows:
A
W
P K K K
d N SH
515 1
.
Ref API 520 Section 3.7.1
Where
A = required effective discharge area of the valve ( in2).
W = required flow through the valve (lb/hr).
P1 = upstream relieving pressure (psia)
Kd = effective coefficient of discharge = 0.975
KN = correction factor for Napier equation.
= 1 where P1 1515 psia.
= (0.1906P1 – 1000)/(0.2292P1 – 1061) where P1 1515 psia and 3215 psia
KSH = superheat steam correction factor. This can be obtained from Table 9 in API RP520.
For saturated steam at any pressure, KSH- = 1.0.
47. OIL & GAS
SIZING CALCULATION
Liquid Phase Relief
• For single phase liquid flow, the sizing method specified for
certified relief valves will be used.
• The following equation only applies to non-flashing liquids.
A
Q
K K K
G
P P
d w v
38 1 2
Ref. API 520 section 4.5.1
Where
A = required effective discharge area of the valve ( in2).
Q = flow rate, in U.S. gallons per minute.
Kd = effective coefficient of discharge that should be obtained from the valve manufacturer.
For a preliminary sizing estimation, a discharge coefficient of 0.65 can be used.
Kw = correction factor due to back-pressure. If the back-pressure is atmospheric, KW = 1.
Balanced-bellows valves in back-pressure service will require the correction factor
determined in Figure 31 in API RP520. Conventional valves require no special correction.
K-V = correction factor due to viscosity as determined from Figure 32 in API RP520.
G = specific gravity of the liquid at the flowing temperature referred to water = 1.0 at 70°F.
P1 = upstream relieving pressure, set pressure plus allowable overpressure (psia).
P2 = back-pressure (psia).
48. OIL & GAS
SIZING CALCULATION
Two Phase Relief
• For 2-phase relief, the methodology in the newly released API 520
Part 1 Appendix D “Sizing for Two-Phase Liquid/Vapour Relief ” shall
be used (see Appendix 1).
• This method has superseded the previous API methods because, in
certain circumstances, it has been found that the previous API
methods for 2-phase flow can undersize PSVs significantly.
• This sizing method is based on the Leung Omega method, which
assumes thermal and mechanical equilibrium; these assumptions
correspond to the Homogeneous Equilibrium Model (HEM).
49. OIL & GAS
SIZING CALCULATION
• Required relief area is calculated from relief rate. Hence
relief rate calculation is very important step
• The case which giving the maximum relief area will be a
governing case.
Choose the worst case scenario to be a governing case
Determine required relief area for each case (Gas, Liquid, 2-Phases)
50. OIL & GAS
SIZING CALCULATION
• Selected standard relief area follows API RP526 or
GPSA chapter 5 Figure 5-7
• Valve body size ( Inlet diameter x Outlet diameter) follows
API STD 526 “Flanged Steel Pressure Relief Valve 4th Ed June 1995”
• Rated flow = (STD relief area) x Relief rate
(Required relief area)
Select proper orifice and valve body size based on STD
51. OIL & GAS
SIZING CALCULATION
Calculate inlet line size (Line ∆P < 3%of RP)
• Inlet line sizing is based on pressure drop less than 3 % of
relieving pressure
Inlet Line design Consideration
• Inlet line size must be at least equal to PSV inlet flange size.
• Inlet piping should slope continuously upward from vessel
to avoid traps.
• Inlet piping should be heat traced if freezing or congealing
of viscous liquids could occur.
52. OIL & GAS
SIZING CALCULATION
Inlet Line design Consideration
• A continual clean purge should be provided if coke/polymer
formation or solids deposition could occur
• CSO valves should have the stem horizontal or vertically
downward
53. OIL & GAS
SIZING CALCULATION
Perform preliminary estimate of tail pipe
• Discharge line sizing is based on Mach No. less than 0.75
Tail Pipe Design Consideration
• Discharge line diameter must be at least equal to PSV outlet
flange size.
• Atmospheric risers should discharge at least 10 ft above
platforms within 50 ft horizontally
• Radiant heat due to ignition of release should be considered.
54. OIL & GAS
SIZING CALCULATION
Tail Pipe Design Consideration
• No check valves, orifice plates or other restrictions
permitted.
• Atmospheric discharge risers should have drain hole.
• CSO valves should have the stem oriented horizontally or
vertically.
• Piping design must consider thermal expansion due to
hot/cold release.
• Autorefrigeration and need for brittle fracture resistant
materials.
55. OIL & GAS
SIZING CALCULATION
Tail Pipe Design Consideration
• Closed discharge piping should slope continuously downward
to header to avoid liquid traps
57. OIL & GAS
SIZING CALCULATION
Perform Flare system modeling to indicate total back pressure and most
suitable tail pipe size.
58. OIL & GAS
SIZING CALCULATION
Select PSV type (Conventional, Balanced Bellow, Pilot Operated
Type
Value
(% if set)
Conventional Balanced Bellow Pilot Operated
Effects on Valves : Gas applications
Back Pressure
Constant
Variable
Superimposed
Variable
Built-up
< 30%
30-50%
>50%
No effect
Lift/Capacity reduced
No effect
Set point increased
by back pressure
Set point increased
by back pressure
Flow become sonic
Generally unstable
Do not use
Flow become
subsonic
Set point varies
with back pressure
10-30%
< 10%
No effect
> 50%
30-50%
Unstable
Do not use Lift/Capacity reduced
Generally unstable
Do not use
No effect
Flow become
subsonic
< 10%
Unstable
Do not use
Lift/Capacity reduced
No effect No effect
No effect
Generally unstable
Do not use
10-30%
> 50%
Flow become
subsonic
59. OIL & GAS
SIZING CALCULATION
Select PSV type (Conventional, Balanced Bellow, Pilot Operated
Type
Value
(% if set)
Conventional Balanced Bellow Pilot Operated
Effects on Valves : Liquid applications
Back Pressure
Constant
Variable
Superimposed
Variable
Built-up
< 20%
20-50%
>50%
No effect
Lift/Capacity reduced
No effect
Set point increased
by back pressure
Set point increased
by back pressure
Flow become sonic
Generally unstable
Do not use
Set point varies
with back pressure
10-20%
< 10%
No effect
> 50%
20-50%
Unstable
Do not use Lift/Capacity reduced
Generally unstable
Do not use
No effect
< 10%
Unstable
Do not use
Lift/Capacity reduced
No effect No effect
No effect
Generally unstable
Do not use
10-20%
> 50%
60. OIL & GAS
EXAMPLE
DP = 400 psig
PAH = 350 psig
OP = 275 psig
OT = 80 oF
DP = 250 psig
OT = 130 oF
CV = 433
SP = 250 psig
SP = 400 psig
CV = 433
FC
FC
V-1
V-2
F-1
F-2
Process Schematic
PSV-1
PSV-2
61. OIL & GAS
EXAMPLE
Assess Relief Scenarios
Scenario Source of
Overpressure
Judement
Scenario to be
considered
separately
1 Fire Case An external fire could cause the pressure
in V-6010 to rise to the relief valve setting
through vaporization of liquids. Equipment
layout shown no potential that “jet fire”
will happen on located area thus “pool fire”
will be determined as a basis for calculation.
Yes
2 Tube Rupture This case is not applicable. No
3 Inlet control
valve failure
CVs are fail to close type therefore this case
is not applicable for sizing PSV.
No
62. OIL & GAS
EXAMPLE
Scenario Source of
Overpressure
Judement
Scenario to be
considered
separately
4 Gas Blow-by Gas blow-by can occur by
• Liquid in a V-1 drop so low that gas
exits via the liquid outlet nozzle due to level
control failure. Loss of liquid level will result
in gas from V-1 passing into V-2 via
F-1 and/or F-2.
Gas blow-by is based on follow assumption
• Control valve upstream fails 100 % open
• The upstream pressure is at the high
pressure alarm.
• The downstream pressure is 110 % of the
set point of the relief valve on the
downstream vessel.
• No possibility that the bypass valve around
the control valve is opened.
Yes
Assess Relief Scenarios
63. OIL & GAS
EXAMPLE
Scenario Source of
Overpressure
Judement
Scenario to be
considered
separately
5 Blocked Outlet 1. Water Blocked Discharge.
This scenario will relates to two trips; first
LIAHH and secondly LAHH. Credit can be
taken that either of these two will actuate.
It is unreasonable to assume both will fail to
response. Hence, this scenario cuts off the
feed to vessel and no relief is needed.
2. Oil Blocked Discharge.
This scenario relates to only oil trip, while
interface level is already healthy. No credit
can be taken that this trip will work. Hence
PSV needs oil relief.
Yes
Assess Relief Scenarios
6 Thermal Relief This case is not applicable. No
64. OIL & GAS
EXAMPLE
Possible Relief Scenarios
There are three different possible relief scenarios :
• Fire Case.
• Gas Blow-by Case.
• Blocked Outlet Case.
65. OIL & GAS
EXAMPLE
Fire Case
Scenario
An external fire could cause the pressure in V-2 to rise to the relief valve
setting through vaporization of liquids. Equipment layout shown no potential
that “jet fire” will happen on located area thus “pool fire” will be determined
as a basis for calculation.
Relief Condition
PSV-2 set pressure = 250 psig
Allowable Accumulation = 21%
Maximum allowable accumulated pressure = 250x1.21 = 302.5 psig.
Relieving temperature = ????
66. OIL & GAS
EXAMPLE
Fire Case
250 psig@61 min ,
relief temperature = 191.5 oF
Since relief can be
initiated after 61 min
fired but API RP 520
allow 15 min to handle
fire hence
“this case will rarely
happen in real operation.”
67. OIL & GAS
EXAMPLE
Fire Case
By input all required parameters (eg. Vessel dimensions, fluid relieving
properties), in to calculation sheet (WS-CA-PR-025, Rev 0)
Required relief area = 0.183 in2
Relief Load = 4,066 lb/hr
Therefore
Select 1xEx2 orifice with discharge area of 0.196 in2
68. OIL & GAS
EXAMPLE
Gas Blow-by
Scenario
Liquid in a V-1 drop so low that gas exits via the liquid outlet nozzle due to
level control failure. Loss of liquid level will result
in gas from V-1 passing into V-2 via F-1 and/or F-2.
Gas blow-by is based on follow assumption
• Control valve upstream fails 100 % open.
• The upstream pressure is at the high pressure alarm.
• The downstream pressure is 110 % of the set point of the relief valve on the
downstream vessel.
• No possibility that the bypass valve around the control valve is opened
as locked close.
(Note : This may need to be considered in some cases).
Relief Condition
PSV-2 set pressure = 250 psig
Allowable Accumulation = 10%
Maximum allowable accumulated pressure = 250x1.1 = 275 psig.
69. OIL & GAS
EXAMPLE
Gas Blow-by
Assume
F-1 and F-2 are same maximum Cv of 433.
C1 assumed 26.5 (C1 is normally obtained from valve vendor)
Assume only one control valve is fail.
Therefore Cg = C1 x Cv = 433 x 26.5 = 11,474.5
V-1 hold pressure at PAH = 350 psig
V-2 operating pressure = 275 psig ( 250 psig x 1.1 = 275 psig)
Differential pressure = 350-275 = 75 psi
Reliving temperature = 80 deg F
How to find the maximum relief rate via F-1 and/or F-2 ?????
70. OIL & GAS
EXAMPLE
Gas Blow-by
Maximum relief rate = 245,703.5 lb/hr
Maximum relief rate
can be evaluated from
control valve sizing
Programs (eg. Fisher,
Masoneilan etc.) or sizing
equations eg.in GPSA.
71. OIL & GAS
EXAMPLE
Gas Blow-by
By input all required parameters (eg. fluid relieving
properties), in to calculation sheet (WS-CA-PR-025, Rev 0) for generally
vapor relief.
Required relief area = 11.57 in2
Relief Load = 245,703.5 lb/hr
Therefore
Select 6xRx8 orifice with discharge area of 16 in2
72. OIL & GAS
EXAMPLE
Blocked Outlet
1. Water Blocked Discharge.
This scenario will relates to two trips; first LIAHH and secondly LAHH.
Credit can be taken that either of these two will actuate. It is unreasonable
to assume both will fail to response. Hence, this scenario cuts off the feed to
vessel and no relief is needed.
2. Oil Blocked Discharge.
This scenario relates to only oil trip, while interface level is already healthy.
No credit can be taken that this trip will work. Hence PSV needs oil relief.
Relief condition
PSV-2 set pressure = 250 psig
Allowable Accumulation = 10%
Maximum allowable accumulated pressure = 250x1.1 = 275 psig.
Relieving temperature = 130 oF
73. OIL & GAS
EXAMPLE
Blocked Outlet
From simulation
Oil flow rate = 508,100 lb/hr (25,000 bpd)
Oil density = 55.21 lb/ft3
By input all required parameters (eg. fluid relieving properties), in to
calculation sheet (WS-CA-PR-025, Rev 0) for generally liquid relief.
Required relief area = 2.76 in2
Therefore select a 3xLx4 orifice with discharge area of 2.853 in2
74. OIL & GAS
EXAMPLE
Relief Case Design Orifice Size Relief Phase
Fire Case 1xEx2 Vapor
Gas Blow-by 6xRx8 Vapor
Blocked Outlet 3xLx4 Liquid
Selection of Governing Relief Scenarios
75. OIL & GAS
EXAMPLE
Therefore the governing case is Gas Blow-by case
Required relief rate = 287,530 lb/hr
Required relief area = 11.57 in2
Selected relief area = 16 in2
Rated flow = 16 x 287,530 lb/hr = 397,621 lb/hr
11.57
Selection of Governing Relief Scenarios
76. OIL & GAS
EXAMPLE
Inlet line sizing calculation
Inlet line sizing calculation is based on pressure drop less
than 3 % of set pressure
PSV set pressure = 250 psig
Allowable pressure drop = 0.03x250 = 7.5 psi
Mass rated flow = 397,621 lb/hr
Based on maximum rated flow and its relief properties
For 8” inlet line, single phase pressure drop is 5.3 psi therefore
suitable for inlet line sizing criteria.
77. OIL & GAS
EXAMPLE
Outlet line sizing calculation
Outlet line sizing calculation is based on the maximum Mach No. of 0.75
From preliminary estimation 12” line give Mach No. of 0.71 hence suitable
for outlet line sizing criteria.
Result from FlareNet modeling show 10” give Mach No. of 0.45 ?????
78. OIL & GAS
EXAMPLE
Selection of Relief Valve Type
Result from FlareNet simulation give total back pressure of 70 psig
PSV set pressure = 250 psig
PSV type
Conventional
Balanced Bellow
Pilot Operated
% of Maximum Back
Pressure Allowable
10% of SP
30% of SP
N/A
Maximum Back
Pressure Allowable
(psig)
25 psig
75 psig
N/A
79. OIL & GAS
EXAMPLE
Summary
6xRx8 Balanced Bellow PSV
Inlet line size is 8”
Outlet line size is 10”
10”
8”x10”
8”x6”
8”
Gas Blow-by
Set@250 psig
Balanced Bellow
