Miscibility & Solubility Fundamentals

1. Introduction to Miscibility and Solubility

Miscibility and solubility are foundational concepts in gas processing and midstream engineering that govern how different substances interact, mix, and distribute between phases. Understanding these properties is essential for designing dehydration systems, amine treating units, lean oil absorption plants, NGL fractionation equipment, and produced water treatment facilities. Nearly every unit operation in a gas processing plant involves the transfer of one or more components between phases, and the thermodynamic principles of miscibility and solubility determine the efficiency and feasibility of each process.

Definitions

Miscibility is the ability of two or more liquids to mix together in all proportions to form a single homogeneous phase. When two liquids are fully miscible, they dissolve completely in each other regardless of the ratio in which they are combined. Ethanol and water are a familiar example of fully miscible liquids. When two liquids are immiscible, they form separate liquid phases when combined—such as oil and water. Many industrially important systems fall between these extremes and are classified as partially miscible, meaning they mix to a limited extent that depends on temperature, pressure, and composition.

Solubility is the capacity of one substance (the solute) to dissolve in another (the solvent) to form a homogeneous solution. Solubility is a quantitative property, expressed as the maximum concentration of solute that can dissolve in a given amount of solvent at specified temperature and pressure conditions. Beyond this saturation limit, additional solute forms a separate phase. Solubility applies to gas-liquid, liquid-liquid, and solid-liquid systems and is one of the most important thermodynamic properties in process engineering.

The "Like Dissolves Like" Principle

A fundamental rule governing miscibility and solubility is the principle of polarity matching: substances with similar molecular polarity tend to be mutually soluble. Nonpolar molecules dissolve readily in nonpolar solvents, and polar molecules dissolve readily in polar solvents. In gas processing terms:

• Hydrocarbons (methane, ethane, propane, hexane, absorption oils) are nonpolar molecules that dissolve readily in other hydrocarbons. This is the basis for lean oil absorption of NGL components from natural gas
• Water is a highly polar molecule that is largely immiscible with hydrocarbons. However, small but operationally significant amounts of water dissolve in hydrocarbons, and trace amounts of hydrocarbons dissolve in water
• Glycols (TEG, DEG, MEG) are polar molecules with hydroxyl groups that make them highly miscible with water but only sparingly soluble in hydrocarbons. This property makes glycols effective dehydration agents
• Amines (MEA, DEA, MDEA) are polar compounds that dissolve readily in water and react chemically with acid gases (H₂S and CO₂), forming the basis for amine treating processes

Temperature and Pressure Effects

Both temperature and pressure significantly affect miscibility and solubility in gas processing systems. The direction and magnitude of these effects depend on the specific system:

These temperature and pressure dependencies are critically important in process design. For example, the strong temperature dependence of water solubility in natural gas is the fundamental reason dehydration is required: gas saturated with water at reservoir conditions will drop liquid water as it cools during gathering and transportation, creating corrosion and hydrate formation risks.

2. Hydrocarbon-Water Phase Behavior

The hydrocarbon-water system is arguably the most important binary system in gas processing engineering. Although hydrocarbons and water are often described as immiscible, they are in fact partially miscible—each dissolves in the other to a small but operationally significant extent. The mutual solubility of water and hydrocarbons governs dehydration system design, produced water treatment requirements, hydrate prediction, and environmental compliance.

Water Content of Natural Gas

Natural gas in equilibrium with liquid water contains water vapor in an amount determined by the temperature, pressure, and gas composition. The water content of sweet natural gas is well-characterized and can be estimated using the GPSA water content charts (McKetta-Wehe correlation), which remain the industry standard for preliminary engineering calculations.

Key relationships for water content of natural gas:

• Temperature dependence: Water content increases approximately exponentially with temperature. Doubling the gas temperature (in absolute terms) can increase water content by an order of magnitude. At 100°F and 1,000 psia, sweet natural gas holds approximately 60 lb water/MMscf; at 150°F and the same pressure, the water content increases to roughly 130 lb/MMscf
• Pressure dependence: Water content decreases with increasing pressure at a given temperature. At 100°F, water content drops from about 220 lb/MMscf at 200 psia to approximately 30 lb/MMscf at 2,000 psia. This decrease is not strictly inversely proportional to pressure because the gas compressibility factor and fugacity corrections become significant at high pressures
• Composition effects: Acid gas components (CO₂ and H₂S) increase the water-carrying capacity of natural gas. The presence of 10% CO₂ can increase water content by 5–10%, and H₂S has an even larger effect. Correction factors per GPSA are applied to account for sour gas compositions

Hydrocarbon Solubility in Water

The solubility of hydrocarbons in water is very low compared to the solubility of water in hydrocarbons, but it is of critical importance for environmental compliance and produced water management. The solubility of individual hydrocarbons in water varies significantly with molecular structure:

The aromatic hydrocarbons (benzene, toluene, ethylbenzene, and xylenes—collectively BTEX) are substantially more soluble in water than the aliphatic hydrocarbons of similar molecular weight. This is because aromatic rings interact with water molecules through pi-electron interactions. BTEX contamination of produced water and glycol regenerator condensate is a major environmental concern in gas processing operations.

Three-Phase Systems

Many gas processing operations involve three coexisting phases: a hydrocarbon-rich vapor, a hydrocarbon-rich liquid, and an aqueous liquid phase. Three-phase behavior is common in:

• Inlet separators: Raw natural gas entering a processing plant typically contains free water, condensed hydrocarbons, and the gas phase. Three-phase separators are standard equipment at plant inlets
• Low-temperature separators (LTS): Chilling natural gas for NGL recovery often produces three phases: residue gas, NGL condensate, and water/hydrate inhibitor solution
• Glycol contactor bottoms: The wet gas-glycol contact can produce a separate hydrocarbon liquid phase along with the rich glycol solution, particularly with rich gas feeds
• Amine unit flash tanks: Rich amine flashed to lower pressure releases dissolved hydrocarbons as a separate phase along with acid gas and the aqueous amine solution

Accurate prediction of three-phase equilibrium requires equations of state (Peng-Robinson, SRK) that can handle both vapor-liquid and liquid-liquid equilibrium simultaneously. The GPSA provides simplified methods for preliminary design, but detailed simulation with validated thermodynamic models is necessary for final equipment sizing.

Temperature Dependence of Mutual Solubility

The mutual solubility of water and hydrocarbons exhibits an important temperature dependence that affects process design at both high and low temperatures. For the water-in-hydrocarbon system, solubility increases monotonically with temperature, which means that hydrocarbon streams saturated at elevated temperatures will release free water as they cool. For the hydrocarbon-in-water system, solubility typically passes through a minimum at approximately 65–85°F for many light hydrocarbons before increasing at both higher and lower temperatures. This unusual behavior results from the complex hydrogen-bonding structure of water and has practical implications for produced water treatment system design.

3. Liquid-Liquid Equilibrium (LLE)

Liquid-liquid equilibrium (LLE) describes the thermodynamic state in which two or more liquid phases coexist in equilibrium. In gas processing, LLE is encountered whenever partially miscible liquids are mixed, forming distinct layers with different compositions. Understanding LLE is essential for designing liquid-liquid extraction processes, sizing three-phase separators, predicting phase splits in glycol and amine systems, and managing hydrocarbon contamination of aqueous process streams.

Immiscible and Partially Miscible Systems

Truly immiscible liquids (zero mutual solubility) do not exist in practice—all liquid pairs exhibit at least trace mutual solubility. However, many systems of engineering interest are effectively immiscible for practical purposes. The important distinction in gas processing is between systems that are:

• Effectively immiscible: Mutual solubility is so low that each phase can be treated as a pure component for material balance purposes. Examples include hexane-water and most heavy hydrocarbon-water systems at ambient conditions
• Partially miscible: Mutual solubility is significant enough to affect process design and material balances. Examples include methanol-hydrocarbon systems, MEG-condensate systems at elevated temperatures, and BTEX-water systems
• Fully miscible above a critical temperature: Some partially miscible systems become fully miscible above a characteristic temperature called the upper critical solution temperature (UCST). Below the UCST, two liquid phases form; above it, a single homogeneous phase exists

Upper and Lower Critical Solution Temperatures

The critical solution temperature (CST) is the temperature at which a partially miscible liquid system transitions between one-phase and two-phase behavior. Two types of critical solution temperatures are recognized:

The existence of a UCST or LCST is determined by the molecular interactions between the two liquid components. Systems with primarily dispersion-force interactions (nonpolar-nonpolar) typically exhibit a UCST. Systems involving hydrogen bonding (such as water-amine or glycol-hydrocarbon) may exhibit a LCST, a UCST, or both (closed-loop miscibility behavior).

Tie Lines and Distribution Coefficients

When a system separates into two liquid phases, the composition of each phase is connected by a horizontal tie line on the phase diagram. The tie line endpoints give the equilibrium compositions of the two coexisting phases at a specific temperature. The distribution coefficient (also called the partition coefficient, K_D) quantifies how a solute distributes between two immiscible phases:

Where x represents the mole fraction (or mass fraction, depending on convention) of the solute in each phase. The distribution coefficient is the fundamental parameter for designing liquid-liquid extraction processes. A large K_D value indicates that the solute strongly prefers one phase over the other, which generally leads to more efficient extraction with fewer theoretical stages.

Applications in Gas Processing

Liquid-liquid equilibrium and extraction processes have several important applications in midstream operations:

• Caustic washing of NGL: Aqueous NaOH solution extracts mercaptans (RSH) and H₂S from liquid NGL products (propane, butane). The process relies on the favorable distribution of sulfur compounds into the caustic phase due to acid-base reactions. This is one of the most common LLE applications in gas processing
• Water washing of NGL: Liquid NGL products are contacted with water to remove methanol or glycol carried over from upstream hydrate inhibition operations. The high polarity of methanol and glycol gives them large distribution coefficients favoring the aqueous phase
• Amine-hydrocarbon phase splits: In amine treating units, the rich amine from the contactor may carry dissolved and entrained hydrocarbons. The flash tank reduces pressure to release light hydrocarbons, and the resulting system can exhibit three-phase (vapor-hydrocarbon liquid-aqueous amine) behavior
• Glycol-hydrocarbon separation: Rich glycol from dehydration contactors contains dissolved BTEX and other hydrocarbons. The glycol regeneration system must manage these hydrocarbons to meet environmental emission limits

Ternary Phase Diagrams

When a third component is added to a binary partially miscible system, the phase behavior becomes more complex and is represented on a triangular (ternary) phase diagram. Ternary diagrams are particularly useful for analyzing extraction processes where a solvent is used to separate two partially miscible components. Each apex of the triangle represents a pure component, each side represents a binary mixture, and interior points represent ternary compositions. The two-phase region is enclosed by a binodal curve, and tie lines within this region connect the compositions of the two equilibrium phases.

4. Solubility in Process Systems

The solubility of gases in liquids and the distribution of components between liquid phases are the thermodynamic foundations for most gas processing unit operations. Absorption, stripping, extraction, and dehydration all depend on favorable solubility relationships to achieve the desired separation. This section examines the key solubility relationships that govern the design and operation of major gas processing systems.

Gas Solubility in Liquids — Henry's Law

The solubility of a sparingly soluble gas in a liquid is described by Henry's Law, which states that the equilibrium concentration of a dissolved gas is directly proportional to its partial pressure in the gas phase above the liquid:

Where p_i is the partial pressure of component i in the gas phase, H_i is the Henry's Law constant (which is temperature-dependent), and x_i is the mole fraction of the dissolved gas in the liquid phase. Henry's Law applies to dilute solutions where the solute does not significantly alter the solvent properties. The Henry's Law constant generally increases with temperature, meaning that gas solubility in liquids decreases as temperature rises—a principle exploited in stripping operations.

In gas processing applications, Henry's Law governs the absorption of trace components such as:

• CO₂ and H₂S in physical solvents (Selexol, Rectisol, NMP)
• Methane and ethane dissolved in glycol solutions
• Light hydrocarbons dissolved in amine solutions (contributing to hydrocarbon losses)
• Oxygen and nitrogen dissolved in process water streams

CO₂ and H₂S Solubility in Amine Solutions

The removal of acid gases (CO₂ and H₂S) from natural gas using aqueous amine solutions is one of the most important solubility-driven processes in gas processing. Unlike physical absorption governed purely by Henry's Law, amine treating involves both physical solubility and chemical reaction, which dramatically increases the total acid gas loading capacity of the solution.

The total acid gas uptake in amine solutions has two components:

• Chemical solubility: Acid gases react with the amine to form heat-stable or regenerable salts and carbamates. This is the dominant absorption mechanism at low acid gas partial pressures (below approximately 50 psia). Chemical reactions are exothermic and temperature-dependent, favoring absorption at lower temperatures and regeneration at higher temperatures
• Physical solubility: At high acid gas partial pressures, the amine becomes saturated with respect to the chemical reaction, and additional absorption occurs by physical dissolution governed by Henry's Law. This becomes increasingly important at pressures above 100–200 psia

Hydrocarbon Absorption in Lean Oil — Raoult's Law and K-Values

In lean oil absorption plants, NGL components (C₃+) are absorbed from natural gas into a heavy hydrocarbon solvent (absorption oil). Because the NGL components and the absorption oil are both hydrocarbons, this system is better described by Raoult's Law and equilibrium K-values rather than Henry's Law:

Where K_i is the equilibrium ratio (K-value) for component i, y_i is the mole fraction in the vapor phase, and x_i is the mole fraction in the liquid phase. For ideal solutions at low pressures, Raoult's Law gives K_i = P_i^sat/P, where P_i^sat is the vapor pressure of pure component i and P is the total system pressure. In practice, K-values for natural gas systems are obtained from GPSA K-value charts or from equations of state (Peng-Robinson, SRK).

Key factors affecting hydrocarbon absorption efficiency:

• Temperature: Lower absorber temperatures favor absorption by reducing K-values. Lean oil plants typically operate absorbers at 80–110°F
• Pressure: Higher pressures reduce K-values and increase absorption. Operating pressures of 400–1,000 psig are typical
• Oil molecular weight: Heavier absorption oils have lower vapor pressures and stronger solvency for NGL components, but higher viscosity reduces tray efficiency
• Oil circulation rate: Higher L/V ratios increase NGL recovery but raise energy costs for oil regeneration

Glycol-Hydrocarbon Interactions and BTEX Absorption

Glycol dehydration systems (primarily TEG) absorb not only water from natural gas but also aromatic hydrocarbons (BTEX) and other hydrocarbons as an unavoidable side effect. The solubility of BTEX in glycol is significantly higher than that of aliphatic hydrocarbons due to the favorable interaction between aromatic pi-electrons and the hydroxyl groups of glycol molecules.

BTEX absorption in glycol systems creates two major concerns:

• Atmospheric emissions: When the rich glycol is regenerated in the reboiler/still column, absorbed BTEX is released to the atmosphere in the regenerator overhead vent. Environmental regulations (40 CFR Part 63, Subpart HH for major sources) require control of these emissions through condensers, carbon adsorption, or incineration
• Glycol degradation: Heavy hydrocarbons that accumulate in the glycol circuit can promote foaming in the contactor, reduce dehydration efficiency, and accelerate thermal degradation of the glycol. Carbon filtration and proper glycol reclaiming are essential for managing hydrocarbon contamination

Pressure and Temperature Effects on Gas Solubility

The response of gas solubility to pressure and temperature changes is central to the design of absorption and stripping operations throughout the gas processing plant. In general:

• Pressure increase → increased gas solubility: This principle drives the design of high-pressure absorbers for acid gas removal (amine contactors at 800–1,200 psig) and NGL recovery (lean oil absorbers at 400–1,000 psig). Higher operating pressures increase the driving force for gas dissolution
• Temperature increase → decreased gas solubility: This principle drives the design of stripping and regeneration operations. Amine regenerators operate at 240–260°F, glycol reboilers at 380–400°F, and lean oil stills at 350–425°F to reverse the absorption and liberate the absorbed gases
• Swing operation: The combination of high-pressure, low-temperature absorption followed by low-pressure, high-temperature stripping is the fundamental operating cycle for all solvent-based gas processing operations

5. Practical Applications in Gas Processing

The principles of miscibility and solubility discussed in the preceding sections manifest in virtually every unit operation in a gas processing plant. This section examines how these fundamental thermodynamic properties are applied in practice to design and operate the major process systems encountered in midstream operations.

Dehydration System Design

Dehydration is required because of the strong temperature dependence of water solubility in natural gas. Gas saturated with water at high-temperature gathering conditions will precipitate liquid water as it cools during pipeline transportation and processing, leading to corrosion, hydrate formation, and slug flow. The dehydration system must reduce the water content of the gas to a level where no liquid water will condense at the lowest anticipated temperature in the downstream pipeline or processing system.

Design considerations driven by solubility fundamentals:

• Water dew point specification: Pipeline specifications typically require a water dew point of −20°F to −40°F (corresponding to approximately 4–7 lb H₂O/MMscf). Cryogenic NGL recovery plants may require water content below 0.1 ppm to prevent ice and hydrate formation in cold sections
• TEG circulation rate: The glycol flow rate is determined by the water removal requirement and the equilibrium water content of the lean glycol at contactor conditions. Higher glycol purity (99.0–99.5+ wt% TEG) achieves lower dew points because the equilibrium water partial pressure over lean glycol decreases with increasing glycol concentration
• Contactor temperature: Lower contactor temperatures reduce the water content of the treated gas because the equilibrium favors water absorption into glycol at lower temperatures. However, temperatures below 50–60°F increase glycol viscosity and reduce tray or packing efficiency
• Number of theoretical stages: Typically 1.5–3.0 theoretical stages are required for standard dehydration, achievable with 6–12 actual trays or 10–20 ft of structured packing

Amine Unit Design

Amine treating systems exploit the chemical and physical solubility of H₂S and CO₂ in aqueous amine solutions to remove acid gases from natural gas. The design of the absorption and regeneration system is fundamentally governed by the vapor-liquid equilibrium relationships between acid gases and the amine solution at absorber and regenerator conditions.

• Amine selection: The choice of amine (MEA, DEA, MDEA, or blends) is driven by the relative solubilities of H₂S and CO₂ and the desired selectivity. MDEA is preferred when selective H₂S removal is required because its tertiary amine structure reacts slowly with CO₂ but rapidly with H₂S
• Rich loading limits: Maximum acid gas loading in the rich amine is limited by corrosion considerations to 0.30–0.45 mol acid gas per mole of amine, depending on the amine type and metallurgy of the system
• Regeneration temperature: The regenerator operates at 240–260°F reboiler temperature to reverse the acid gas absorption reactions and reduce the lean loading to 0.005–0.015 mol/mol for deep treating applications
• Hydrocarbon co-absorption: Hydrocarbons dissolve in amine solutions per Henry's Law, resulting in hydrocarbon losses in the acid gas stream. Rich amine flash tanks operating at 50–75 psig recover most of the dissolved hydrocarbons before regeneration

Lean Oil Plant Design

Lean oil absorption plants recover NGL from natural gas by exploiting the favorable solubility of C₃+ hydrocarbons in a heavy absorption oil. The design of the absorber, rich-oil demethanizer, and oil purification still is governed by vapor-liquid equilibrium K-values that determine component distribution between the gas and oil phases.

• Absorption oil selection: The ideal absorption oil maximizes NGL solubility (low K-values for C₃+) while maintaining acceptable viscosity and thermal stability. The GPSA provides K-value data for estimating absorption performance as a function of oil molecular weight, temperature, and pressure
• Absorber design: The number of theoretical stages and L/V ratio are determined from absorption factor calculations based on K-values. Typical designs use 6–12 theoretical stages for 80–95% propane recovery
• Stripping system: The demethanizer and oil purification still reverse the absorption process by raising the temperature and reducing the pressure to increase K-values, driving the absorbed components back into the vapor phase

NGL Treating — Caustic Washing

Liquid NGL products (propane, butane) must meet sulfur specifications before sale. Caustic (NaOH) washing removes mercaptans and H₂S from liquid hydrocarbons through a liquid-liquid extraction process where the distribution coefficient for sulfur compounds strongly favors the caustic phase due to acid-base reactions:

• Mercaptan extraction: RSH + NaOH → NaSR + H₂O. The reaction is reversible, and spent caustic can be regenerated by oxidation of the mercaptide to disulfide
• H₂S removal: H₂S + 2NaOH → Na₂S + 2H₂O. This reaction is essentially irreversible at the concentrations involved
• CO₂ removal: CO₂ + 2NaOH → Na₂CO₃ + H₂O. CO₂ consumes caustic and competes with mercaptan extraction

Caustic treaters are typically designed as packed columns, static mixers, or fiber-film contactors to provide intimate liquid-liquid contact between the NGL and caustic phases. Settling drums downstream allow phase separation before the treated NGL proceeds to storage or pipeline delivery.

Environmental Considerations

The solubility of hydrocarbons in produced water and the absorption of BTEX in glycol and amine systems create environmental compliance requirements that are directly linked to miscibility and solubility fundamentals:

Hydrate Formation and Inhibitor Selection

Gas hydrates form when water molecules create a crystalline lattice around small gas molecules (methane, ethane, propane, CO₂, H₂S) at elevated pressures and low temperatures. Hydrate formation is a solubility phenomenon: it occurs when the conditions favor the solid hydrate phase over the liquid water and dissolved gas phases. Hydrate prediction methods (Katz, Baillie-Wichert, or simulation-based approaches) estimate the temperature and pressure conditions at which hydrates become thermodynamically stable.

Thermodynamic hydrate inhibitors work by altering the solubility relationships in the water-gas system:

• Methanol (MeOH): Fully miscible with water. Reduces hydrate formation temperature by 2–4°F per wt% methanol in the aqueous phase. Effective but expensive due to high vapor losses (methanol has significant solubility in the hydrocarbon vapor phase). Typical injection rates: 0.5–2.0 gal/MMscf
• Monoethylene glycol (MEG): Fully miscible with water. Similar depression effect to methanol but much lower vapor losses due to lower vapor pressure. Preferred for continuous injection in subsea and offshore applications. Typical injection concentration: 60–80 wt% in the aqueous phase
• Triethylene glycol (TEG): Miscible with water, very low vapor pressure. Used primarily for dehydration (continuous contact) rather than hydrate inhibition (injection), but the dehydration effect prevents hydrate formation by removing water from the gas
• Low-dosage hydrate inhibitors (LDHI): Kinetic inhibitors (KHI) and anti-agglomerants (AA) do not alter bulk water solubility but interfere with hydrate crystal nucleation or growth at very low concentrations (0.5–3.0 wt%). These are specialty chemicals used when thermodynamic inhibitor quantities would be impractical

References

1. GPSA, Chapter 1 — General Information (Phase Behavior and Physical Properties)
2. GPSA, Chapter 20 — Dehydration
3. GPSA, Chapter 21 — Hydrocarbon Treating
4. GPA Standard 2140 — Liquefied Petroleum Gas Specifications
5. API Standard 521 — Pressure-Relieving and Depressuring Systems