Boiling & Freezing Point Fundamentals

1. Boiling Point Fundamentals

The boiling point of a pure substance is the temperature at which its vapor pressure equals the surrounding pressure, allowing the liquid to undergo a phase transition to vapor throughout its bulk. For engineering purposes, the normal boiling point (NBP) is defined as the boiling temperature at standard atmospheric pressure (14.696 psia or 1 atm). The normal boiling point is one of the most fundamental physical properties used in hydrocarbon processing, serving as the primary indicator of component volatility and as the basis for separation process design.

In the midstream gas processing industry, boiling points determine which components can be separated by distillation, at what pressures pipelines must operate to keep fluids in a single phase, and what temperatures are required for cryogenic processing. Understanding how boiling points change with pressure is essential for every aspect of facility design from wellhead separation through NGL fractionation.

Normal Boiling Points of Common Components

Effect of Pressure on Boiling Point

The boiling point of any substance increases with increasing pressure and decreases under vacuum conditions. This relationship is fundamental to nearly every separation process in gas processing. Distillation columns operate at specific pressures to position the boiling points of key components at temperatures that are practical for available heating and cooling utilities. Pressurized pipelines keep light hydrocarbons in the liquid phase by maintaining system pressure above their vapor pressure at the operating temperature.

The quantitative relationship between vapor pressure and temperature is described by the Clausius-Clapeyron equation, which provides an analytical approximation assuming constant heat of vaporization over the temperature range of interest:

Where P₁ and P₂ are the vapor pressures at temperatures T₁ and T₂ (in absolute units, Rankine or Kelvin), ΔH_vap is the molar heat of vaporization (BTU/lbmol or J/mol), and R is the universal gas constant (1.987 BTU/lbmol·R or 8.314 J/mol·K). This equation can be rearranged to solve for the boiling temperature at any given pressure, provided the normal boiling point and heat of vaporization are known.

Vapor Pressure Curves

A vapor pressure curve plots the equilibrium pressure between liquid and vapor phases as a function of temperature. Each pure component has a unique vapor pressure curve that begins at the triple point (where solid, liquid, and vapor coexist) and terminates at the critical point (where the distinction between liquid and vapor disappears). At any point along the curve, the substance exists simultaneously as liquid and vapor in equilibrium.

For engineering calculations, the Antoine equation provides a more accurate representation of vapor pressure data than the Clausius-Clapeyron equation, as it accounts for the temperature dependence of the heat of vaporization through empirically fitted constants. However, the Clausius-Clapeyron equation remains valuable for quick estimates and for understanding the fundamental thermodynamic relationship between pressure and boiling point.

Practical Significance

In pipeline operations, the boiling point at the operating pressure determines whether a given component will be liquid or vapor. For example, propane has a normal boiling point of -43.7°F, meaning it is a gas at atmospheric conditions. However, at 200 psig (approximately 215 psia), propane's boiling point increases to approximately 128°F, allowing it to be transported as a liquid at ambient temperatures. This principle underlies the design of NGL pipelines, LPG storage facilities, and pressurized transport vessels.

2. Freezing Point and Pour Point

The freezing point of a pure substance is the temperature at which the liquid phase transitions to a solid crystalline structure at a given pressure. For most hydrocarbons, the freezing point is far below normal operating temperatures in gas processing plants, but it becomes critically important in cryogenic applications, arctic pipeline operations, and certain specialized processes where operating temperatures approach or fall below the freezing range of heavier components.

Freezing Point vs. Pour Point

While the freezing point refers to the thermodynamic phase transition temperature for a pure substance, the pour point is a practical measurement applied to petroleum mixtures and crude oils. The pour point is defined as the lowest temperature at which a liquid still flows under standardized test conditions (ASTM D97). For crude oils and heavy hydrocarbon mixtures, the pour point is typically higher than the true freezing point because wax crystals begin to form and interlock before the entire mass solidifies, creating a gel-like structure that prevents flow.

Significance in Pipeline Operations

Freezing and pour points are critical considerations in several midstream pipeline scenarios. For waxy crude oil pipelines operating in cold climates, the pipeline must be maintained above the pour point to prevent gel formation and potential pipeline blockage. If a waxy crude pipeline shuts down in cold weather and the product temperature drops below the pour point, restart can become extremely difficult or impossible without heating the pipeline from the outside.

For natural gas pipelines, the freezing point of heavier components is generally not a concern because operating temperatures remain well above the freezing range of C₁ through C₅ hydrocarbons (all below -130°F). However, water and CO₂ present special concerns. Water freezes at 32°F, and even small amounts of free water can form ice blockages in cold-weather pipeline operations. CO₂ can form dry ice (solid CO₂) at temperatures below -109°F, which is relevant in cryogenic processing where CO₂ freeze-out can plug heat exchanger passages.

Wax Appearance Temperature

The wax appearance temperature (WAT), also called the cloud point, is the temperature at which the first wax crystals become visible in a cooling petroleum liquid. The WAT is always above the pour point and represents the onset of solid formation rather than the point where flow ceases. For pipeline design, the WAT is often more operationally relevant than either the freezing point or pour point, because wax deposition on pipe walls begins at this temperature, reducing flow area and increasing pressure drop over time.

Wax deposition management strategies include thermal insulation, chemical inhibitors (pour point depressants and wax crystal modifiers), regular pigging operations to scrape wax deposits from the pipe wall, and heat tracing for critical sections such as subsea flowlines and above-ground crossings in arctic environments.

Hydrate Formation Temperature vs. Freezing Point

Gas hydrates are crystalline solid structures in which water molecules form a cage-like lattice that traps gas molecules (primarily methane, ethane, propane, and CO₂). Hydrate formation temperature is entirely different from the freezing point of either the water or the gas component. Hydrates can form at temperatures well above the freezing point of water (32°F), sometimes up to 60–80°F depending on gas composition and pressure. This makes hydrate prevention a far more common operational concern than ice formation in most gas gathering and transmission systems.

The distinction between hydrate formation and freezing is critical for field operations: injecting methanol or glycol as a hydrate inhibitor addresses hydrate formation but does not prevent ice formation if free water drops below 32°F. Similarly, dehydrating the gas to remove water vapor prevents both hydrate formation and ice formation, which is why dehydration is the preferred long-term solution for gas pipeline water management.

3. Mixture Phase Behavior

Unlike pure components, which have a single boiling point at a given pressure (where liquid and vapor coexist at exactly one temperature), mixtures exhibit a range of temperatures over which liquid and vapor phases coexist. This temperature range is bounded by the bubble point (lower temperature, onset of vaporization) and the dew point (higher temperature, onset of condensation). Understanding this two-phase behavior is essential for designing separators, distillation columns, heat exchangers, and pipelines that handle hydrocarbon mixtures.

Bubble Point and Dew Point Definitions

The bubble point is the temperature (at a given pressure) at which the first infinitesimal bubble of vapor forms from a liquid mixture. Below the bubble point, the mixture exists entirely as a subcooled liquid. At the bubble point, the liquid composition equals the overall composition, and the first vapor bubble has a composition enriched in the most volatile components. The bubble point condition is expressed mathematically as:

The dew point is the temperature (at a given pressure) at which the first infinitesimal droplet of liquid forms from a vapor mixture. Above the dew point, the mixture exists entirely as a superheated vapor. At the dew point, the vapor composition equals the overall composition, and the first liquid drop is enriched in the least volatile (heaviest) components. The dew point condition is expressed as:

Where z_i is the mole fraction of component i in the overall mixture, and K_i is the equilibrium ratio (K-value) defined as K_i = y_i/x_i, the ratio of vapor-phase to liquid-phase mole fraction at equilibrium.

Raoult's Law for Ideal Mixtures

For ideal liquid mixtures where the components are chemically similar (such as a mixture of paraffin hydrocarbons), Raoult's Law provides a reasonable first approximation for the K-values. Raoult's Law states that the partial pressure of each component above the liquid is equal to its pure-component vapor pressure multiplied by its mole fraction in the liquid:

Where P_vap,i(T) is the pure-component vapor pressure at temperature T, and P is the total system pressure. This relationship is most accurate for mixtures of similar components (e.g., C₃/C₄/C₅ paraffin mixtures) at moderate pressures. As pressure increases or as the components become more dissimilar (e.g., methane with heavy hydrocarbons, or hydrocarbons with water), deviations from Raoult's Law become significant.

Real Mixture Deviations

Real hydrocarbon mixtures deviate from ideal (Raoult's Law) behavior for several reasons. At high pressures, molecular interactions in both the liquid and vapor phases become significant, and the assumption of ideal gas behavior in the vapor phase breaks down. For mixtures containing components with very different molecular sizes (e.g., methane with n-octane), molecular interactions in the liquid phase cause deviations from the ideal mixing assumption.

For engineering-accuracy calculations in gas processing, equation-of-state (EOS) methods such as the Soave-Redlich-Kwong (SRK) or Peng-Robinson (PR) equations are used instead of Raoult's Law. These methods account for molecular interactions through binary interaction parameters and provide accurate K-values across the full range of pressures and temperatures encountered in gas processing operations. Process simulation software (such as HYSYS, ProMax, or ProII) implements these EOS methods for rigorous phase equilibrium calculations.

Phase Envelopes

A phase envelope (also called a P-T diagram) maps the bubble point and dew point curves for a given mixture composition across a range of pressures and temperatures. The region enclosed by the bubble point and dew point curves represents the two-phase region where liquid and vapor coexist. Two important points on the phase envelope define the limits of two-phase behavior:

• Cricondenbar: The maximum pressure at which two phases can coexist. Above the cricondenbar, the mixture exists as a single dense phase regardless of temperature. Operating a pipeline above the cricondenbar pressure ensures single-phase flow and eliminates liquid dropout concerns
• Cricondentherm: The maximum temperature at which two phases can coexist. Above the cricondentherm, the mixture is always a single vapor phase regardless of pressure. For lean natural gas, the cricondentherm is typically between -20 and +50°F at pipeline pressures, which means liquid dropout is possible at normal ambient temperatures

Pipeline designers use the phase envelope to select operating pressures and temperatures that either avoid the two-phase region entirely (single-phase design) or account for two-phase flow (multiphase pipeline design). The phase envelope shifts with composition, so any change in inlet gas composition can alter the two-phase boundary and potentially cause unexpected liquid formation.

4. Critical Properties

The critical point of a pure substance is the unique temperature and pressure above which the distinction between liquid and vapor phases ceases to exist. At the critical point, the densities of the liquid and vapor phases become identical, the surface tension drops to zero, and the heat of vaporization approaches zero. Above the critical temperature, no amount of pressure can condense the substance into a liquid; it exists as a supercritical fluid with properties intermediate between those of a liquid and a gas.

Critical Temperature and Critical Pressure

Several patterns are evident in the critical property data. As molecular weight increases within the normal paraffin series (methane through octane), the critical temperature increases and the critical pressure decreases. This means heavier hydrocarbons can exist as liquids at higher temperatures but require less pressure to liquefy. Components with strong intermolecular forces (hydrogen bonding in water, dipole interactions in H₂S and CO₂) have relatively high critical pressures compared to non-polar hydrocarbons of similar molecular weight.

Reduced Properties

Reduced properties express the actual temperature and pressure as fractions of the critical values, providing a dimensionless framework for comparing the behavior of different substances:

Where T and T_c are in absolute units (Rankine or Kelvin), and P and P_c are in consistent pressure units (psia or kPa). The reduced temperature and pressure are the basis for the principle of corresponding states, which is one of the most powerful concepts in thermodynamics for predicting physical properties of substances.

Corresponding States Principle

The principle of corresponding states asserts that all substances at the same reduced temperature and reduced pressure have approximately the same compressibility factor, fugacity coefficient, and other thermodynamic departure functions. This principle allows engineers to predict properties of one substance based on known properties of another, and it forms the theoretical foundation for generalized correlations used in gas processing calculations.

In practice, the two-parameter corresponding states principle (using only T_r and P_r) works well for simple, nearly spherical molecules (methane, nitrogen, argon) but becomes less accurate for larger, more asymmetric molecules. The acentric factor (ω), introduced by Pitzer, serves as a third parameter that improves corresponding states correlations by accounting for molecular shape and polarity:

The acentric factor is zero for simple spherical molecules (argon), small and positive for most hydrocarbons (0.011 for methane, 0.152 for propane, 0.301 for n-hexane), and larger for polar molecules (0.344 for water). Modern equation-of-state methods (SRK, Peng-Robinson) incorporate the acentric factor as a key input parameter for predicting thermodynamic properties.

Pseudo-Critical Properties for Mixtures

For gas mixtures, pseudo-critical properties are calculated as mole-fraction-weighted averages of the component critical properties using Kay's mixing rule:

These pseudo-critical values are used with the reduced property framework to estimate compressibility factors and other mixture properties. For natural gas mixtures containing significant amounts of CO₂ or H₂S, Wichert-Aziz corrections must be applied to the pseudo-critical properties to account for the non-hydrocarbon interactions.

5. Process Design Applications

Boiling point and freezing point data are foundational to nearly every process design decision in midstream gas processing and pipeline engineering. This section describes the primary applications where these physical properties directly influence design choices and operating strategies.

Distillation Column Design

The relative volatility between adjacent components in a distillation column is directly related to the ratio of their vapor pressures (and therefore their boiling points) at the column operating temperature. Components with widely separated boiling points are easier to separate, requiring fewer theoretical stages and lower reflux ratios. Components with close boiling points (such as isobutane at 10.9°F NBP and n-butane at 31.1°F NBP, a difference of only 20.2°F) require many stages and high reflux ratios for sharp separation.

The relative volatility (α) between two components is defined as:

Where component i is more volatile (lighter) than component j. A relative volatility of 1.0 means the components are inseparable by distillation. Typical relative volatilities in NGL fractionation range from 1.5 to 4.0 for adjacent components in the C₂–C₅ range. The depropanizer (C₃/C₄ separation) has a higher relative volatility than the deisobutanizer (iC₄/nC₄ separation), which is why depropanizers require fewer stages.

Flash Calculation Basis

Flash calculations determine the equilibrium vapor and liquid phase amounts and compositions when a feed stream at known composition, temperature, and pressure undergoes a phase change. The flash calculation is the most fundamental vapor-liquid equilibrium calculation in process engineering and is used to size separators, determine two-phase pipeline flow regimes, and design heat exchangers that operate in the two-phase region.

The Rachford-Rice equation, which is solved iteratively for the vapor fraction (V/F), is the standard method for isothermal flash calculations. The K-values used in this equation are functions of temperature and pressure that are ultimately derived from the same vapor pressure and critical property data discussed in the preceding sections.

Pipeline Operating Temperature Selection

For single-phase gas pipelines, the operating temperature must remain above the dew point of the gas at the local pressure to prevent liquid dropout. Liquid accumulation in gas pipelines causes slug flow, increased pressure drop, metering errors, and potential corrosion from condensed water. Pipeline designers use the phase envelope to determine the minimum operating temperature at each point along the pipeline, accounting for pressure decline due to friction and temperature changes due to ambient heat transfer.

For single-phase liquid pipelines (such as NGL or condensate lines), the operating pressure must remain above the bubble point pressure at the local temperature to prevent vapor formation. Vapor pockets in liquid pipelines reduce throughput, cause pump cavitation, and create vapor lock conditions. The bubble point pressure increases with temperature, so the highest-temperature locations along the pipeline (typically the pump discharge or sun-exposed above-ground sections) are the most critical for maintaining single-phase liquid flow.

Cold Climate Operations

In arctic and cold climate environments, pipeline and facility design must account for the interaction between low ambient temperatures and fluid phase behavior. Key design considerations include:

• Wax deposition: When crude oil or condensate pipelines operate below the wax appearance temperature, paraffin wax deposits on the pipe wall, progressively reducing the effective diameter. Pipeline insulation, pour point depressant injection, and regular pigging programs are required to manage wax buildup
• Hydrate prevention: Gas gathering systems in cold climates are particularly susceptible to hydrate formation because the combination of high pressure and low temperature puts the operating point well within the hydrate formation region. Continuous methanol or MEG injection at wellheads and pipeline low points is standard practice
• Freeze protection: Instrument lines, control valve bodies, and small-bore piping are vulnerable to ice formation from trapped water. Heat tracing and insulation are required for all dead legs and low-flow areas where water might accumulate
• Restart after shutdown: Cold restart of pipelines and facilities requires careful attention to the phase state of the pipeline contents, which may have cooled to ambient temperature during the shutdown. Wax gelling, hydrate formation, and ice blockages can all prevent successful restart

Cryogenic Processing Temperature Requirements

Cryogenic gas processing plants, which operate at temperatures as low as -150 to -180°F for deep NGL and ethane recovery, must consider the freezing points and solid formation characteristics of all components in the gas stream. The primary cryogenic concerns are:

The design of cryogenic plants requires rigorous phase equilibrium calculations using equation-of-state methods that can accurately predict solid-fluid equilibria in addition to vapor-liquid equilibria. The formation of solid CO₂ is the most common operational problem in cryogenic ethane recovery plants, and feed gas CO₂ specifications are set to maintain a comfortable margin above the CO₂ freezing boundary throughout the process.

References

1. GPSA, Chapter 1 — General Information
2. GPA Standard 2145 — Table of Physical Constants of Paraffin Hydrocarbons and Other Components of Natural Gas
3. API Technical Data Book — Petroleum Refining
4. GPSA, Chapter 20 — Dehydration