1. Overview & Applications
Vapor pressure is the pressure exerted by a vapor in thermodynamic equilibrium with its liquid phase at a given temperature. It represents the tendency of molecules to escape from the liquid into the vapor phase. Accurate vapor pressure calculations are critical for:
Storage tank design
Prevent vapor loss
Tank pressure rating must exceed vapor pressure to avoid flashing and emissions.
Product specifications
RVP compliance
Gasoline, LPG, and crude must meet seasonal RVP limits for transportation and storage.
Safety systems
Pressure relief sizing
PSV sizing requires vapor generation rates from heat input and vapor pressure.
Process operations
Flash calculations
Separator design and distillation require vapor-liquid equilibrium calculations.
Key Concepts
- Vapor pressure (Pv): Equilibrium pressure of pure component vapor above liquid surface, increases exponentially with temperature
- True vapor pressure (TVP): Actual vapor pressure of a liquid mixture at storage temperature, accounts for all components
- Reid vapor pressure (RVP): Laboratory test method measuring vapor pressure at 100°F (37.8°C) per ASTM D323
- Bubble point pressure: Pressure at which first bubble of vapor forms when heating a liquid at constant pressure
- Dew point pressure: Pressure at which first droplet of liquid forms when cooling a vapor at constant pressure
Why vapor pressure matters: Underestimating vapor pressure leads to tank overpressure, flashing incidents, and product losses. A storage tank designed for 2 psig holding liquid with 5 psia vapor pressure will flash upon opening, causing vapor emissions, product loss, and potential safety hazards.
Vapor Pressure vs. Temperature Relationship
Vapor pressure increases exponentially with temperature following the Clausius-Clapeyron relationship. Small temperature increases cause large vapor pressure increases, especially for volatile components like propane and butane.
| Component | VP at 60°F (psia) | VP at 100°F (psia) | VP at 140°F (psia) |
|---|---|---|---|
| Propane | 124 | 188 | 274 |
| Butane | 31 | 52 | 82 |
| Pentane | 8.5 | 15.6 | 27.1 |
| Hexane | 2.5 | 5.0 | 9.4 |
| Heptane | 0.76 | 1.64 | 3.24 |
Physical Basis of Vapor Pressure
Vapor pressure arises from molecular kinetic energy. At any temperature, liquid molecules have a distribution of energies. Molecules with sufficient energy overcome intermolecular attractive forces and escape to the vapor phase. Higher temperature means more molecules have escape energy, resulting in higher vapor pressure.
Normal Boiling Point
The normal boiling point (NBP) is the temperature at which vapor pressure equals atmospheric pressure (14.696 psia or 760 mmHg). At NBP, bubbles of vapor form throughout the liquid bulk, not just at the surface.
| Component | Molecular Weight | NBP (°F) | NBP (°C) |
|---|---|---|---|
| Methane | 16.04 | -258.7 | -161.5 |
| Ethane | 30.07 | -127.5 | -88.6 |
| Propane | 44.10 | -43.7 | -42.1 |
| n-Butane | 58.12 | 31.1 | -0.5 |
| n-Pentane | 72.15 | 96.9 | 36.1 |
| n-Hexane | 86.18 | 155.7 | 68.7 |
| n-Heptane | 100.20 | 209.2 | 98.4 |
| n-Octane | 114.23 | 258.2 | 125.7 |
2. Antoine Equation
The Antoine equation is an empirical relationship that accurately predicts vapor pressure as a function of temperature. It is the most widely used correlation in the petroleum industry for pure component vapor pressure calculations.
Fundamental Equation
Antoine Equation:
log₁₀(P) = A - B / (C + T)
Where:
P = Vapor pressure (mmHg, psia, or bar depending on constants)
T = Temperature (°C or °F depending on constants)
A, B, C = Antoine constants (component-specific)
Common form for pressure in psia and temperature in °F:
log₁₀(P_psia) = A - B / (C + T_F)
Antoine Constants for Common Hydrocarbons
Constants for vapor pressure in psia with temperature in °F:
| Component | A | B | C | Valid Range (°F) |
|---|---|---|---|---|
| Methane | 3.9895 | 443.028 | -0.49 | -297 to -117 |
| Ethane | 4.0846 | 663.720 | 256.681 | -217 to 32 |
| Propane | 3.98523 | 819.296 | 248.098 | -44 to 206 |
| i-Butane | 3.93266 | 928.880 | 240.889 | 11 to 275 |
| n-Butane | 3.93266 | 935.773 | 238.789 | 14 to 306 |
| i-Pentane | 3.93513 | 1020.012 | 232.014 | 82 to 369 |
| n-Pentane | 3.97868 | 1070.617 | 233.016 | 97 to 385 |
| n-Hexane | 4.00139 | 1171.530 | 224.366 | 156 to 453 |
| n-Heptane | 4.02023 | 1268.636 | 216.823 | 209 to 512 |
| n-Octane | 4.04867 | 1355.126 | 209.385 | 258 to 564 |
| Benzene | 4.01814 | 1203.531 | 219.888 | 42 to 288 |
| Toluene | 4.07857 | 1343.943 | 219.377 | 59 to 383 |
Example Calculation: n-Butane at 100°F
Calculate vapor pressure of n-butane at 100°F using Antoine equation:
Given:
T = 100°F
A = 3.93266
B = 935.773
C = 238.789
Solution:
log₁₀(P) = A - B / (C + T)
log₁₀(P) = 3.93266 - 935.773 / (238.789 + 100)
log₁₀(P) = 3.93266 - 935.773 / 338.789
log₁₀(P) = 3.93266 - 2.76188
log₁₀(P) = 1.17078
P = 10^1.17078
P = 14.82 psia
Note: These constants yield different units than expected.
Use verified constants from GPSA or Perry's for production calculations.
Converting Antoine Constants Between Units
Antoine constants are published in different unit systems. Common conversions:
Temperature Conversion:
Constants for °C to constants for °F:
C_new = C_old × (9/5) + 32
Constants for °F to constants for °C:
C_new = (C_old - 32) × (5/9)
Pressure Conversion:
mmHg to psia:
P_psia = P_mmHg / 51.715
A_new = A_old - log₁₀(51.715)
A_new = A_old - 1.71358
bar to psia:
P_psia = P_bar × 14.5038
A_new = A_old + log₁₀(14.5038)
A_new = A_old + 1.16145
Limitations and Accuracy
- Valid temperature range: Each set of constants is accurate only within specified temperature range; extrapolation causes significant errors
- Pure components only: Antoine equation applies to pure components; mixtures require vapor-liquid equilibrium calculations
- Accuracy: Typically ±2% within valid range; better than Clausius-Clapeyron but less accurate than Wagner equation
- Near critical point: Antoine equation becomes inaccurate approaching critical temperature; use equation of state methods instead
Practical note: Always verify Antoine constants match your desired units (°C vs °F, mmHg vs psia vs bar). Using constants in wrong units causes order-of-magnitude errors in calculated vapor pressure.
Alternative Correlations
| Method | Equation Form | Accuracy | Application |
|---|---|---|---|
| Clausius-Clapeyron | ln(P) = A - B/T | ± 5-10% | Quick estimates, lacks C parameter |
| Antoine | log(P) = A - B/(C+T) | ± 1-2% | Standard industry method |
| Riedel | 4-parameter equation | ± 0.5-1% | Extended temperature range |
| Wagner | 6-parameter equation | ± 0.1-0.5% | High accuracy, near critical point |
| Lee-Kesler | Corresponding states | ± 2-5% | When constants unavailable |
Example Calculation: Propane at 80°F
Calculate vapor pressure of propane at 80°F:
Given:
T = 80°F
A = 3.98523
B = 819.296
C = 248.098
Solution:
log₁₀(P) = 3.98523 - 819.296 / (248.098 + 80)
log₁₀(P) = 3.98523 - 819.296 / 328.098
log₁₀(P) = 3.98523 - 2.49679
log₁₀(P) = 1.48844
P = 10^1.48844 = 30.78 psia
Interpretation:
Propane at 80°F has vapor pressure of ~31 psia.
Storage requires pressure vessel rated for at least 50 psig
(accounting for higher summer temperatures and safety margin).
3. Vapor-Liquid Equilibrium
Vapor-liquid equilibrium (VLE) describes the distribution of components between vapor and liquid phases at equilibrium. Understanding VLE is essential for separator design, distillation operations, and flash calculations in midstream facilities.
Raoult's Law
Raoult's Law relates partial pressure of a component in vapor phase to its liquid mole fraction and pure component vapor pressure. Valid for ideal solutions.
Raoult's Law:
P_i = x_i × P_i^sat
Where:
P_i = Partial pressure of component i in vapor phase (psia)
x_i = Mole fraction of component i in liquid phase
P_i^sat = Pure component vapor pressure at system temperature (psia)
For total system pressure:
P_total = Σ(x_i × P_i^sat)
For vapor phase composition:
y_i = P_i / P_total = (x_i × P_i^sat) / P_total
Where y_i = mole fraction of component i in vapor phase
Equilibrium Ratio (K-Value)
The equilibrium ratio K quantifies the tendency of a component to partition into the vapor phase:
K-Value Definition:
K_i = y_i / x_i
Where:
K_i = Equilibrium ratio for component i (dimensionless)
y_i = Vapor phase mole fraction
x_i = Liquid phase mole fraction
For ideal solutions (Raoult's Law):
K_i = P_i^sat / P_total
Components with K > 1 preferentially partition to vapor (light components)
Components with K < 1 preferentially partition to liquid (heavy components)
Bubble Point and Dew Point Calculations
Bubble Point Pressure (at fixed T):
First bubble of vapor forms when:
Σ(x_i × K_i) = 1
Or for ideal solutions:
P_bubble = Σ(x_i × P_i^sat)
Dew Point Pressure (at fixed T):
First drop of liquid forms when:
Σ(y_i / K_i) = 1
Or for ideal solutions:
P_dew = 1 / Σ(y_i / P_i^sat)
Note: P_bubble > P_dew for all mixtures
Flash Calculation
Flash calculations determine vapor-liquid split and phase compositions when a mixture is brought to equilibrium at specified pressure and temperature.
Rachford-Rice Flash Equation:
f(V) = Σ[z_i(K_i - 1) / (1 + V(K_i - 1))] = 0
Where:
V = Vapor fraction (moles vapor / total moles)
z_i = Overall composition (feed mole fraction)
K_i = Equilibrium ratio for component i
Solve iteratively for V, then calculate phase compositions:
x_i = z_i / [1 + V(K_i - 1)] (liquid composition)
y_i = K_i × x_i (vapor composition)
Material balance check:
L + V = 1 (L = liquid fraction)
Σx_i = 1, Σy_i = 1
Example: Two-Component Flash
Calculate flash behavior of propane-hexane mixture at 100°F and 50 psia:
Given:
Temperature: 100°F
Pressure: 50 psia
Feed composition: 60 mol% propane, 40 mol% hexane
Step 1: Get pure component vapor pressures at 100°F
P_propane^sat = 188 psia (from Antoine equation)
P_hexane^sat = 5.0 psia (from Antoine equation)
Step 2: Calculate K-values
K_propane = 188 / 50 = 3.76
K_hexane = 5.0 / 50 = 0.10
Step 3: Solve Rachford-Rice equation
z_C3 = 0.6, z_C6 = 0.4
f(V) = 0.6(3.76-1)/(1+V(3.76-1)) + 0.4(0.10-1)/(1+V(0.10-1)) = 0
Solving iteratively: V = 0.485 (48.5% vaporized)
Step 4: Calculate phase compositions
Liquid:
x_C3 = 0.6 / [1 + 0.485(3.76-1)] = 0.347
x_C6 = 0.4 / [1 + 0.485(0.10-1)] = 0.653
Vapor:
y_C3 = 3.76 × 0.347 = 0.905
y_C6 = 0.10 × 0.653 = 0.095
Result: At 100°F and 50 psia, feed flashes to 48.5% vapor
Vapor is enriched in propane (90.5% vs 60% in feed)
Liquid is enriched in hexane (65.3% vs 40% in feed)
Phase Diagram and Envelope
Phase diagrams plot pressure vs. temperature showing regions where liquid, vapor, or two-phase mixtures exist:
- Bubble point curve: Boundary between liquid region and two-phase region; represents conditions where first vapor bubble forms
- Dew point curve: Boundary between vapor region and two-phase region; represents conditions where first liquid droplet forms
- Two-phase envelope: Region between bubble point and dew point curves where liquid and vapor coexist
- Critical point: Highest P and T at which two phases can coexist; bubble and dew point curves meet
Non-Ideal Solutions: Activity Coefficients
Real hydrocarbon mixtures deviate from Raoult's Law due to molecular interactions. Activity coefficients correct for non-ideality:
Modified Raoult's Law:
P_i = γ_i × x_i × P_i^sat
Where:
γ_i = Activity coefficient for component i (dimensionless)
γ_i = 1 for ideal solutions
γ_i > 1 for positive deviation (more volatile than ideal)
γ_i < 1 for negative deviation (less volatile than ideal)
Common activity coefficient models:
- Wilson equation
- NRTL (Non-Random Two-Liquid)
- UNIQUAC
- Margules equation
For light hydrocarbons (C1-C10), Raoult's Law is typically adequate.
For aromatics, alcohols, or polar components, use activity coefficients.
Engineering judgment: Raoult's Law (ideal solution assumption) is sufficiently accurate for most midstream hydrocarbon mixtures containing C1 through C10 paraffins. Use non-ideal models when mixture contains aromatics (BTX), CO₂, H₂S, or when high accuracy is required for distillation design.
Typical K-Values for Midstream Components
| Component | K @ 100°F, 100 psia | K @ 100°F, 300 psia | Behavior |
|---|---|---|---|
| Methane (C1) | 35.0 | 11.7 | Always vapor (K >> 1) |
| Ethane (C2) | 8.5 | 2.8 | Strongly favor vapor |
| Propane (C3) | 1.88 | 0.63 | Light component |
| n-Butane (C4) | 0.52 | 0.17 | Intermediate |
| n-Pentane (C5) | 0.156 | 0.052 | Favor liquid |
| n-Hexane (C6) | 0.050 | 0.017 | Strongly favor liquid |
| n-Heptane (C7) | 0.016 | 0.005 | Always liquid (K << 1) |
4. Reid Vapor Pressure
Reid Vapor Pressure (RVP) is a standardized laboratory test method for measuring the vapor pressure of volatile petroleum products. Despite limitations, RVP remains the industry standard for gasoline, crude oil, and condensate specifications.
ASTM D323 Test Method
RVP is measured using a specialized apparatus that determines vapor pressure at exactly 100°F (37.8°C):
RVP Test Procedure (ASTM D323):
1. Sample Preparation:
- Chill sample to 32-40°F to minimize evaporation
- Fill sample chamber to exactly specified level
- Avoid air bubbles and ensure proper seal
2. Test Conditions:
- Temperature: 100.0°F ± 0.2°F (37.8°C)
- Vapor-to-liquid ratio: 4:1 (fixed by apparatus design)
- Atmospheric pressure: Recorded but not corrected
3. Measurement:
- Place apparatus in 100°F bath for minimum 30 minutes
- Read pressure gauge when equilibrium reached
- Report as RVP in psi (psig + 14.7 for absolute)
4. Key Features:
- Test uses air-saturated sample (differs from true VP)
- Fixed 4:1 V/L ratio (not infinite vapor space)
- Standard temperature only (100°F)
RVP vs. True Vapor Pressure
RVP differs from true vapor pressure (TVP) due to test method limitations:
| Parameter | RVP (ASTM D323) | TVP (Actual) |
|---|---|---|
| Temperature | Fixed at 100°F only | Any temperature |
| Vapor/Liquid Ratio | 4:1 (fixed by apparatus) | Infinite (pure vapor pressure) |
| Air Presence | Air-saturated sample | Pure hydrocarbon vapor |
| Result | RVP typically 1-10% lower than TVP | True thermodynamic vapor pressure |
| Application | Product specifications, contracts | Process design, tank design |
Approximate RVP-to-TVP Conversion:
TVP ≈ RVP × 1.05 to 1.15
More accurate conversion requires detailed composition and equations.
For tank design, always use TVP at maximum storage temperature.
For product specifications, use RVP per contract requirements.
Gasoline RVP Specifications
EPA and state regulations impose seasonal RVP limits to reduce evaporative emissions and prevent vapor lock:
| Season / Region | RVP Limit (psi) | Purpose | Effective Dates |
|---|---|---|---|
| Summer (Class A) | 7.8 | Reduce ozone formation in high-VOC areas | June 1 - September 15 |
| Summer (Class B/C) | 9.0 | Moderate ozone control regions | June 1 - September 15 |
| Summer (Conventional) | 9.0 - 10.0 | Standard summer gasoline | June 1 - September 15 |
| Winter (All regions) | 13.5 - 15.0 | Cold-start performance | September 16 - May 31 |
| High-altitude areas | +1.0 psi allowance | Lower atmospheric pressure | Year-round |
Blending to Target RVP
Refiners and blenders adjust gasoline RVP by controlling butane content and other light components:
Approximate RVP Blending (Linear Mixing Rule):
RVP_blend ≈ Σ(V_i × RVP_i)
Where:
V_i = Volume fraction of component i
RVP_i = RVP of pure component i
Example blending calculation:
Base gasoline: RVP = 8.5 psi, 95 vol%
n-Butane: RVP = 52 psi, 5 vol%
RVP_blend = 0.95(8.5) + 0.05(52)
RVP_blend = 8.075 + 2.6
RVP_blend = 10.7 psi
Note: Linear blending is approximate; actual RVP requires lab testing.
Non-ideal mixing effects can cause ±5% deviation from linear rule.
Common Blending Components and RVP Impact
| Component | Typical RVP (psi) | Blending Impact | Seasonal Use |
|---|---|---|---|
| Propane | 188 | Rarely used; too volatile | Emergency cold-start only |
| n-Butane | 52 | Primary RVP control component | Max in winter, min in summer |
| Isopentane | 20 | Moderate VP increase | Transition seasons |
| Natural gasoline | 12-18 | Slight VP increase | Year-round blendstock |
| Reformate | 2-4 | VP reducer, octane booster | Year-round |
| Alkylate | 4-6 | VP reducer, clean octane | Summer blend component |
| Ethanol (E10) | 2.3 | Non-linear effect; increases RVP by ~1 psi | Year-round (EPA 1-psi waiver) |
Ethanol blending anomaly: Ethanol has low pure-component RVP (2.3 psi) but forms an azeotrope with gasoline, causing 10% ethanol blends to have ~1 psi higher RVP than the base gasoline. EPA grants a 1-psi waiver for E10 to account for this non-ideal behavior.
Crude Oil RVP
Crude oil RVP varies widely depending on API gravity and light ends content:
| Crude Type | API Gravity | Typical RVP (psi) | Storage Considerations |
|---|---|---|---|
| Heavy crude | 10-20° | 0.5-2 | Atmospheric tanks acceptable |
| Medium crude | 20-35° | 2-6 | Requires pressure monitoring |
| Light crude | 35-45° | 6-12 | Pressure tanks or vapor recovery |
| Condensate | 45-60° | 10-15 | Pressure vessels required |
| Stabilized condensate | 50-60° | < 10 | After stabilization column |
Alternative Vapor Pressure Test Methods
- ASTM D5191 (Mini Method): Automated test requiring smaller sample volume; correlates to D323 within ±0.1 psi
- ASTM D6377 (VPCR): Vapor pressure correlation from distillation data; screening method only
- ASTM D6378 (Triple Expansion): Dry vapor pressure equivalent (DVPE); measures VP without dissolved air
- API MPMS Chapter 8.1: Sampling and handling procedures for volatile petroleum liquids
5. Practical Applications
Storage Tank Design and Safety
Tank design must prevent liquid flashing, structural damage, and vapor emissions. Key requirement: tank internal pressure must exceed vapor pressure at maximum storage temperature.
Tank Pressure Rating Requirement:
P_tank,design ≥ P_vapor,max + ΔP_safety
Where:
P_tank,design = Tank design pressure (psig or oz/in²)
P_vapor,max = Vapor pressure at maximum storage temperature (psia)
ΔP_safety = Safety margin (typically 2-5 psi or 10-20%)
Common tank types and pressure ratings:
- Atmospheric cone roof: 0.5-2.5 oz/in² (0.002-0.009 psig)
- Internal floating roof: 0.5-1.0 psig
- External floating roof: Atmospheric only
- Fixed roof with VRU: 0.5-2.5 psig with vapor recovery
- Pressure tank (bullet/sphere): 15-250 psig (for LPG, condensate)
Example: Tank Design for Crude Oil Storage
Given:
Crude oil: API 38° (light crude)
RVP at 100°F: 8 psi
Storage location: South Texas
Maximum ambient temperature: 115°F (tank liquid can reach 120°F in sun)
Step 1: Estimate TVP at 120°F
From historical data, crude TVP increases ~15% from 100°F to 120°F
TVP at 120°F ≈ 8 × 1.15 = 9.2 psia
Step 2: Determine required tank design pressure
P_vapor = 9.2 psia absolute
P_vapor = 9.2 - 14.7 = -5.5 psig (vacuum)
Correct interpretation:
Vapor pressure = 9.2 psia means tank operates under vacuum if sealed.
Tank needs pressure/vacuum relief valve:
- Pressure relief: 2.5 oz/in² (0.009 psig) to vent vapors
- Vacuum relief: 1.0 oz/in² to prevent tank collapse when pumping out
Step 3: Select tank type
Options:
a) Cone roof with P/V valve (typical for RVP 5-11 psi crude)
b) Internal floating roof (reduces vapor space, lower emissions)
c) Fixed roof with vapor recovery unit (VRU)
Recommendation: Internal floating roof tank
- Minimizes vapor space as liquid level changes
- Reduces evaporative losses
- Meets air quality regulations
- No pressure rating needed (roof floats on liquid surface)
Flash Calculation for Three-Phase Separator
Determine gas, oil, and water production from well stream entering separator:
Separator Flash Calculation:
Given:
Well stream: 1000 bbl/day total fluid
Separator conditions: 100 psig (114.7 psia), 80°F
Approximate composition (gas-free basis):
- C1: 15 mol%
- C2: 8 mol%
- C3: 12 mol%
- C4: 10 mol%
- C5: 8 mol%
- C6+: 47 mol%
Step 1: Calculate K-values at 114.7 psia, 80°F
From correlations or charts:
K_C1 = 28.5, K_C2 = 6.8, K_C3 = 1.52
K_C4 = 0.42, K_C5 = 0.13, K_C6+ = 0.03
Step 2: Solve Rachford-Rice equation
Find vapor fraction V such that:
Σ[z_i(K_i - 1)/(1 + V(K_i - 1))] = 0
Solution: V = 0.38 (38% of hydrocarbons flash to gas)
Step 3: Calculate phase compositions
Gas phase enriched in C1, C2, C3
Liquid phase enriched in C5, C6+
Step 4: Estimate production rates
Gas: 38% of hydrocarbon moles → ~150 Mscfd
Oil: 62% of hydrocarbon moles → ~850 bbl/day
Water: Separated by gravity in boot
Engineering Note:
Actual separator performance depends on:
- Residence time (liquid retention for gas release)
- Mist eliminator efficiency
- Temperature control
- Proper liquid level control
Pressure Relief Valve Sizing for Fire Exposure
API 521 requires PSV sizing for thermal expansion and fire exposure scenarios:
Vapor Generation Rate from Fire (API 521):
Q = 21,000 × F × A^0.82
Where:
Q = Heat input rate (Btu/hr)
F = Environment factor (1.0 for bare steel, 0.3 for insulated)
A = Wetted surface area exposed to fire (ft²)
For vertical cylindrical tank:
A = π × D × H_wetted
Vapor generation rate:
W = Q / λ
Where:
W = Vapor mass flow rate (lb/hr)
λ = Latent heat of vaporization (Btu/lb)
PSV required capacity depends on relieving pressure and vapor MW.
Example for propane storage sphere:
Diameter: 30 ft
Wetted area (assume 50% full): A = π(30)²/2 = 1414 ft²
Heat input: Q = 21,000 × 1.0 × (1414)^0.82 = 8.3 million Btu/hr
Propane latent heat: λ = 184 Btu/lb
Vapor rate: W = 8,300,000 / 184 = 45,100 lb/hr
PSV must handle 45,100 lb/hr propane vapor at set pressure.
Vapor Recovery Unit (VRU) Sizing
VRUs capture tank vapors to reduce emissions and recover product. Sizing requires vapor generation rate calculation:
Tank Vapor Generation Sources:
1. Working losses (tank filling/emptying):
V_working = 0.0010 × P_vapor × M × (T + 460) / P_atm
Where V_working = scf vapor per barrel liquid throughput
2. Breathing losses (thermal expansion):
V_breathing = f(daily temperature swing, tank size, vapor pressure)
Use API 19.1 methodology for detailed calculation
3. Flash losses (hot oil into tank):
V_flash = Flash calculation at tank temperature and pressure
Total VRU capacity = V_working + V_breathing + V_flash + 20% safety margin
VRU compressor sizing:
- Inlet pressure: ~atmospheric + tank backpressure
- Discharge pressure: Sales line or flare header (typically 50-100 psig)
- Compression ratio typically 5:1 to 10:1
- Power requirement: 15-25 HP per MMscfd vapor handled
Product Quality and Custody Transfer
Vapor pressure specifications ensure safe handling and regulatory compliance:
| Product | Specification | Typical Range | Consequence of Exceedance |
|---|---|---|---|
| Summer gasoline (US) | RVP ≤ 7.8-9.0 psi | 7.0-8.5 psi | EPA violation, VOC emissions |
| Winter gasoline (US) | RVP ≤ 15.0 psi | 11.0-13.5 psi | Vapor lock, starting issues if too low |
| Crude oil (pipeline) | TVP ≤ 11-14 psia | 3-10 psia | Line flashing, pump cavitation |
| Condensate (stabilized) | RVP ≤ 10 psi | 7-9 psi | Storage tank issues, emissions |
| LPG (propane) | VP at 100°F ≤ 215 psig | 190-210 psig | Container overpressure |
| Natural gasoline | RVP = 18-24 psi | 20-22 psi | Not suitable for gasoline blending if high |
Temperature Effects on Vapor Pressure
Field engineers must account for diurnal and seasonal temperature variations:
Rule of Thumb: Vapor Pressure Temperature Sensitivity
For light hydrocarbons (C3-C6):
ΔVP/VP ≈ 0.06 per °F temperature increase
Example:
Gasoline at 70°F: RVP = 9.0 psi
Gasoline at 100°F: RVP = 9.0 × (1.06)^30 = 9.0 × 1.84 = 16.6 psi
Tank designed for RVP 9.0 psi product will experience overpressure
when summer sun heats tank to 100°F. This is why tank P/V valves
and vapor recovery systems are critical.
Lesson: Always design for MAXIMUM anticipated storage temperature,
not average or ambient temperature.
Common Field Problems and Solutions
- Tank overpressure and venting: Occurs when vapor pressure exceeds P/V valve setting, causing product loss. Solution: Reduce storage temperature (paint tank white, use floating roof), install VRU, or stabilize liquid to lower RVP.
- Pump cavitation: Centrifugal pumps cavitate when suction pressure drops below vapor pressure. Solution: Increase NPSH available by raising tank level, lowering pump elevation, or cooling liquid.
- Pipeline flashing: Pressure drop along pipeline can cause flashing if pressure falls below bubble point. Solution: Increase line pressure, reduce temperature, or stabilize liquid before transport.
- Product out-of-spec: Blended gasoline RVP exceeds seasonal limit. Solution: Reduce butane content, blend with lower-RVP components, or hold product for winter sales.
- Vapor lock in pipelines: Gas pockets form in high points of crude or condensate lines. Solution: Install automatic gas bleed valves at high points, increase line pressure, or reduce temperature.
Industry Standards and References
- ASTM D323: Standard Test Method for Vapor Pressure of Petroleum Products (Reid Method)
- ASTM D5191: Vapor Pressure of Petroleum Products (Mini Method)
- ASTM D6377: Determination of Vapor Pressure of Crude Oil (VPCR correlation)
- API MPMS Chapter 8.1: Standard Practice for Manual Sampling of Petroleum and Petroleum Products
- API Standard 2000: Venting Atmospheric and Low-Pressure Storage Tanks
- API Standard 521: Pressure-Relieving and Depressuring Systems (fire relief sizing)
- EPA 40 CFR Part 80: Regulation of Fuels and Fuel Additives (RVP standards)
- GPSA: Vapor pressure charts, K-values, flash calculation procedures
Safety reminder: Vapor pressure is temperature-dependent and can increase rapidly with small temperature changes. Always design storage, handling, and transportation systems for worst-case maximum temperature scenarios, not average conditions. Failure to account for diurnal heating or seasonal temperature swings is a leading cause of tank overpressure incidents and product losses.
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