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API MPMS 19.3G (1997, Reaffirmed 2002): Standard Practice for Determining Hydrocarbon Volatility by the Pressure-Temperature Method
Essential Guidelines for Evaporative Loss Measurement in the Manual of Petroleum Measurement Standards
1. Scope and Application
API MPMS 19.3G (Part G of Chapter 19 of the Manual of Petroleum Measurement Standards) provides a standardized practice for determining the volatility of hydrocarbon mixtures — including crude oil, petroleum products, and liquefied petroleum gases (LPG) — using the pressure-temperature (P-T) correlation method. Originally published in 1997 and reaffirmed in 2002, this standard remains a key reference for quantifying evaporative losses from storage tanks, marine vessels, and transport loading operations.
The standard is specifically intended to measure the true vapor pressure (TVP) and to evaluate the propensity of a hydrocarbon fluid to generate vapors under defined temperature conditions. This data is essential for calculating evaporative loss rates in accordance with API MPMS Chapter 19 (Evaporative Loss Measurement) and for complying with environmental regulations such as the U.S. EPA’s emission reporting programs.
Typical applications include:
- Determination of vapor pressure for crude oil and petroleum fractions in refineries and terminals.
- Input data for tank emissions models (e.g., EPA AP-42, TANKS software).
- Custody transfer adjustments involving volatile components.
- Compliance with vapour recovery and vapour tightness requirements.
2. Technical Requirements and Methodology
2.1 Principle of the Pressure-Temperature Method
The method prescribed in API MPMS 19.3G employs a closed-system pressure measurement at a test temperature representative of the fluid’s storage temperature. A sample is conditioned to a specified volume ratio (liquid/vapor) and then heated in a water bath until equilibrium pressure is reached. The measured pressure is interpolated to a reference temperature (or to the actual tank temperature) using the P-T correlation curves provided in the standard.
2.2 Equipment Specifications
| Parameter | Requirement / Value | Notes |
|---|---|---|
| Vapor Pressure Apparatus | Stainless steel cylinder with internal volume ~100–150 cm³ | Must be capable of withstanding test pressures up to 2,000 kPa |
| Sample Volume | Volumetric ratio liquid/vapor = 1:4 (or as specified in method) | Precision measurement with graduated injection or weight check |
| Temperature Bath | Water or oil bath controlled to ±0.1 °C | Must cover the range of interest (typically 0–100 °C) |
| Pressure Sensor | Digital transducer or mercury manometer, accuracy ±0.1% of full scale | Calibrated against a certified traceable standard |
| Conditioning Step | Shaking and temperature equilibration for at least 10 minutes | Ensure complete vapor-liquid equilibrium before reading |
2.3 Procedure Outline
- Sampling: Obtain a representative sample of the hydrocarbon mixture using a floating-piston cylinder or a pressurized sampling system. Minimize flashing and contamination.
- Preconditioning: Chill the apparatus and sample to a temperature at which the vapor pressure is negligible (e.g., 0 °C) to introduce a known volume into the test cell.
- Heating: Place the cell in the temperature bath set to the desired test temperature (typically 37.8 °C, 50 °C, or the bulk liquid temperature). Agitate periodically.
- Pressure Measurement: Record the equilibrium pressure after temperature stability is achieved. Repeat at multiple temperatures if a full P-T curve is needed.
- Data Reduction: Apply the P-T correlation from API MPMS 19.3G to convert measured pressure to vapor pressure at the reference temperature (e.g., 37.8 °C true vapor pressure).
2.4 Precision and Bias
The standard includes repeatability and reproducibility limits based on inter-laboratory studies. Typical repeatability for a single laboratory is ±2 kPa (at 95% confidence) for a mid-range vapor pressure product. Reproducibility across laboratories is approximately ±4 kPa. The bias relative to more direct methods (e.g., ASTM D5191) is reported to be within ±3 kPa when proper corrections are applied.
Tip: Always precondition the apparatus with an inert gas purge before introducing the sample to avoid condensation and ensure accurate air-free measurements. Use fresh, dehumidified nitrogen for best results.
Caution: For samples containing high concentrations of methane or hydrogen sulfide, the standard P-T correlation may underestimate true vapor pressure. Consult API MPMS 19.3G Appendix B for correction factors applicable to off-gas streams.
3. Implementation Highlights
3.1 Integration with Evaporative Loss Calculation Workflows
API MPMS 19.3G is intended to be used in conjunction with other parts of Chapter 19, such as:
- API MPMS 19.1 – Evaporative Loss from Fixed-Roof Tanks
- API MPMS 19.2 – Evaporative Loss from Floating-Roof Tanks
- API MPMS 19.4 – Evaporative Loss from Marine Vessel Loading
The vapor pressure values obtained by Part G serve as direct input to the standing loss and working loss equations. Accurate vapor pressure data reduce the uncertainty in loss estimates and support more precise emission inventories.
3.2 Laboratory Quality Assurance
To achieve consistent results, operating companies should:
- Train technicians in handling pressurized volatile samples.
- Perform daily verification checks using a certified reference material (e.g., a stable hydrocarbon blend with known VP).
- Participate in proficiency testing programmes (e.g., ASTM inter-laboratory crosscheck).
- Maintain a calibration log for temperature baths and pressure sensors.
3.3 Relationship with ASTM and ISO Standards
The methodology of API MPMS 19.3G shares many elements with ASTM D6897 (Standard Test Method for Vapor Pressure of Petroleum Products (Mini Method)) and ISO 4256 (Petroleum products – Determination of vapour pressure – Reid method). However, the P-T correlation approach of 19.3G is tailored specifically for the wide boiling-range mixtures typical of crude oil and condensate handling. Many terminal operating procedures incorporate 19.3G alongside ASTM D5191 for compliance with local regulations.
Best Practice: When implementing 19.3G in a regulated pipeline or marine loading operation, cross‑validate the results with a secondary method (e.g., a online vapour pressure analyzer) at least once per quarter. This ensures consistency and early detection of systemic errors.
4. Compliance and Reaffirmation Notes
4.1 Status and Dates
API MPMS 19.3G was originally published in 1997 and reaffirmed in 2002 without changes to the technical content. The reaffirmation indicates that the committee judged the standard to remain valid and adequate for its intended purpose. While no later revision has been issued, the document is still widely cited in regulatory guidance and industry loss‑calculation manuals.
4.2 Regulatory References
Several U.S. state and federal environmental agencies reference API MPMS 19.3G for:
- Calculating storage tank emissions under Clean Air Act permits (Title V).
- Determining vapor pressure in vapour recovery system design.
- Verifying compliance with vapor pressure limits for gasoline blending.
Outside the U.S., the standard is adopted in some jurisdictions as an alternative to ISO 4256 or ISO 9120. Operators should check local acceptance of the reaffirmed 2002 version.
4.3 Comparison with Recent Methods
Since 2002, newer test methods have emerged, such as ASTM D7799 (vapor pressure of crude oil by automated vapor pressure instrument) and the ERG (Expansion Reduction Gauge) method. These methods often offer faster cycle times and lower sample volumes. However, API MPMS 19.3G remains valuable for its well‑documented P‑T correlation curves, which are designed to yield highly accurate results for complex hydrocarbon mixtures at temperatures typical of storage and transit.
4.4 Maintenance of Competency
Because the standard is now over two decades old, it is critical that technicians and engineers using it have a deep understanding of the underlying thermodynamics. Regular refresher training and review of the associated API publications (e.g., Technical Bulletin 19) are recommended to avoid misapplication.
Important: Do not use the 1997/2002 version of 19.3G to substitute for a direct measurement of vapor pressure in a stream that contains significant amounts ( >5 % by weight) of volatile components with critical points near the test temperature. In such cases, use a method specifically designed for supercritical fluids (e.g., ASTM D6378).
FAQs
Q: What is the difference between API MPMS 19.3G and the Reid Vapor Pressure (RVP) method (ASTM D323)?
A: RVP (ASTM D323) uses an open-cup method with a vapor-to-liquid ratio of 4:1 at 37.8°C and is limited to gasoline and volatile petroleum products. API MPMS 19.3G uses a closed-cell, pressure‑temperature correlation and is applicable to a wider range of hydrocarbons, including crude oil and LPG, at temperatures up to the bubble point. It also gives true vapor pressure, not a Reid equivalent.
A: RVP (ASTM D323) uses an open-cup method with a vapor-to-liquid ratio of 4:1 at 37.8°C and is limited to gasoline and volatile petroleum products. API MPMS 19.3G uses a closed-cell, pressure‑temperature correlation and is applicable to a wider range of hydrocarbons, including crude oil and LPG, at temperatures up to the bubble point. It also gives true vapor pressure, not a Reid equivalent.
Q: Is API MPMS 19.3G still considered current even though it was only reaffirmed in 2002?
A: Yes. The API reaffirms standards regularly, and the 2002 reaffirmation is the latest action on Part G. Many regulatory programs and industry practices continue to accept the 2002 version. However, users should check if any errata or addenda have been issued by API (none exist as of 2025). For new installations, many operators combine 19.3G with later methods for verification.
A: Yes. The API reaffirms standards regularly, and the 2002 reaffirmation is the latest action on Part G. Many regulatory programs and industry practices continue to accept the 2002 version. However, users should check if any errata or addenda have been issued by API (none exist as of 2025). For new installations, many operators combine 19.3G with later methods for verification.
Q: What sample handling precautions are most important for accurate results?
A: The sample must be taken without flashing or loss of light ends. Use a floating-piston cylinder or a pressured sampling loop. Cool the sample below ambient before opening the valve. Prevent air or water ingress. For viscous samples, preheat the apparatus and condition the sample slowly to avoid thermal shock.
A: The sample must be taken without flashing or loss of light ends. Use a floating-piston cylinder or a pressured sampling loop. Cool the sample below ambient before opening the valve. Prevent air or water ingress. For viscous samples, preheat the apparatus and condition the sample slowly to avoid thermal shock.
Q: Can I use API MPMS 19.3G results directly in EPA emission models?
A: Yes, the true vapor pressure obtained from 19.3G is the recommended input for the TANKS model and AP‑42 equations. Be sure to convert the measured pressure to the actual storage temperature using the P‑T correlations in the standard. Some models require the daily average liquid surface temperature; the standard provides methods for that conversion.
A: Yes, the true vapor pressure obtained from 19.3G is the recommended input for the TANKS model and AP‑42 equations. Be sure to convert the measured pressure to the actual storage temperature using the P‑T correlations in the standard. Some models require the daily average liquid surface temperature; the standard provides methods for that conversion.
Article prepared for general educational purposes. Always refer to the latest official API publication or your local regulatory body for definitive requirements.
© 2026 Technical Review – API MPMS 19.3G (1997, Reaffirmed 2002)