Glycol/Propane Combined Dew Point System Fundamentals

1. Combined Dew Point Control Overview

Pipeline-quality natural gas must meet both a water dew point specification (to prevent corrosion and hydrate formation) and a hydrocarbon dew point specification (to prevent liquid dropout in downstream pipelines). Conventional approaches treat these two requirements separately: a glycol dehydration unit removes water, followed by a mechanical refrigeration or Joule-Thomson system for hydrocarbon dew point control. The combined glycol/propane system addresses both specifications in a single integrated cooling step, reducing equipment count, plot space, and operating complexity.

In the combined process, glycol is injected into the gas stream upstream of the chilling section. The glycol serves as a hydrate inhibitor, allowing the gas to be cooled well below its hydrate formation temperature without forming solid hydrate plugs. The chiller—typically using propane as the refrigerant—cools the gas to temperatures between −20°F and −40°F, condensing both water and heavier hydrocarbons simultaneously. The cooled gas then enters a low-temperature separator (LTS) where the three phases (dry gas, hydrocarbon condensate, and rich glycol) are separated.

Why Combine the Two Systems?

The primary advantage of the combined system is process simplification. A standalone TEG dehydration unit followed by a separate refrigeration plant requires two major process units, each with its own equipment train, control loops, and maintenance requirements. The combined glycol/propane system eliminates the contactor tower entirely and handles water removal through physical condensation at low temperature, with glycol serving only as a hydrate inhibitor rather than an absorbent.

Process Flow Sequence

Typical Operating Temperature Ranges

The combined system is widely used in gas gathering, gas processing, and offshore production platforms where space and weight constraints favor integrated solutions. It is particularly effective for rich gas streams where significant NGL recovery accompanies the dew point control.

2. Process Configuration

Glycol Injection

Lean glycol is injected into the gas stream at a point upstream of any heat exchange equipment where the gas temperature will drop below its hydrate formation temperature. The injection point is critical: glycol must be present before any cooling occurs to prevent hydrate formation on heat exchanger surfaces. Injection is typically accomplished using a spray nozzle or injection quill that ensures good distribution of glycol droplets across the gas flow cross-section.

The most common glycol for low-temperature separator systems is monoethylene glycol (MEG). MEG is preferred over diethylene glycol (DEG) or triethylene glycol (TEG) for LTS applications because of its lower viscosity at cold temperatures, superior hydrate depression per unit weight, and lower solubility losses to the hydrocarbon phase. TEG, while dominant in conventional contactor-based dehydration, becomes too viscous at temperatures below approximately 0°F to flow effectively.

Glycol Type Comparison for LTS Service

Gas-Gas Exchanger

The gas-gas exchanger (also called the feed-effluent exchanger) is a critical component for energy efficiency. The cold dry gas leaving the LTS passes through the shell side (or alternate passages in a plate-fin exchanger) while warm inlet gas with injected glycol flows through the tube side. This arrangement recovers 50–70% of the cooling energy, significantly reducing the refrigeration compressor duty. Common exchanger types include shell-and-tube, plate-fin (brazed aluminum), and printed-circuit heat exchangers (PCHE). Plate-fin exchangers offer the highest thermal effectiveness in a compact footprint and are the standard choice for cryogenic and near-cryogenic gas processing applications.

Approach temperatures of 5–15°F are typical for the gas-gas exchanger. A closer approach reduces chiller duty but increases exchanger surface area and capital cost. The optimum approach is determined by a tradeoff between refrigeration operating cost and exchanger capital cost.

Propane Chiller

The propane chiller provides the mechanical refrigeration needed to cool the gas from the gas-gas exchanger outlet temperature down to the target LTS temperature. Propane is the refrigerant of choice for temperatures down to approximately −40°F because its boiling point at atmospheric pressure is −44°F, providing adequate temperature driving force. For temperatures below −40°F, cascade refrigeration systems (propane/ethylene or propane/ethane) or mixed-refrigerant systems are required.

The chiller is typically a kettle-type shell-and-tube heat exchanger with propane boiling on the shell side and gas flowing through the tubes. The propane refrigeration cycle includes a compressor (reciprocating or screw type), condenser (air-cooled or water-cooled), receiver, and expansion valve.

Low-Temperature Separator (LTS)

The LTS is a three-phase separator operating at the coldest point in the process. It separates the chilled stream into three distinct phases:

• Gas phase (top): Dry sales gas meeting both water and hydrocarbon dew point specifications
• Hydrocarbon liquid phase (middle): Condensed NGL (C₃+ or C₅+) for further processing or sales
• Glycol/water phase (bottom): Rich glycol that has absorbed water from the gas, plus any free water

The LTS must be sized with adequate residence time for the glycol-hydrocarbon interface to separate cleanly. MEG and hydrocarbon liquids are largely immiscible but can form stable emulsions at low temperatures, particularly in the presence of fine solids, corrosion products, or naturally occurring surfactants. Typical liquid residence times of 5–10 minutes for the glycol phase and 3–5 minutes for the hydrocarbon phase are used to ensure clean separation.

Glycol Regeneration

Rich glycol from the LTS is routed to the regeneration system to remove absorbed water and restore the lean glycol concentration for re-injection. The regeneration train typically includes:

• Flash drum: Reduces pressure and releases dissolved gas from the rich glycol. Flash gas is used as fuel or sent to flare.
• Filters: Particulate filter (5–10 micron) followed by activated carbon filter to remove hydrocarbons and degradation products from the glycol stream
• Rich/lean glycol exchanger: Preheats rich glycol using hot lean glycol, reducing reboiler duty
• Reboiler: Heats glycol to regeneration temperature (375–400°F for MEG) to drive off water vapor. Fired reboiler or steam-heated units are used depending on site utilities.
• Stripping column: Provides additional stages of water removal above the reboiler. Stripping gas (dry natural gas or nitrogen) may be used to achieve lean glycol concentrations above 85 wt%
• Surge tank/accumulator: Provides lean glycol storage and pump suction head for the injection pump

3. Design Considerations

Glycol Injection Rate

The glycol injection rate is determined by the amount of water that must be absorbed from the gas and the required hydrate temperature depression. The injection rate must satisfy two constraints simultaneously: (1) provide sufficient glycol mass flow to absorb all condensed water without diluting the glycol below its effective concentration, and (2) maintain glycol concentration high enough at the coldest point to depress the hydrate formation temperature below the operating temperature with an adequate safety margin (typically 5–10°F).

The Hammerschmidt equation provides a first approximation of the hydrate temperature depression achievable with a given glycol concentration:

Where ΔT is the hydrate temperature depression (°F), K_H is a constant (2,335 for MEG, 2,222 for DEG, 2,000 for TEG), W is the weight percent of the inhibitor in the liquid water/glycol phase at the coldest point, and M is the molecular weight of the glycol. For MEG at 80 wt% concentration in the aqueous phase, the predicted hydrate depression is approximately 55°F, adequate for LTS temperatures down to roughly −30°F when the uninhibited hydrate temperature is approximately 25°F.

For more accurate hydrate depression calculations at high glycol concentrations, the Nielsen-Bucklin equation is preferred:

Where a_w is the activity of water in the glycol/water solution. This equation is more accurate than Hammerschmidt at glycol concentrations above 60 wt% and at temperatures below −10°F.

Lean Glycol Concentration

Lean glycol concentration for LTS applications is typically 80–85 wt% MEG, compared to 98.5–99.5 wt% TEG for conventional contactor dehydration. The lower concentration requirement arises because the glycol in an LTS system serves as a hydrate inhibitor (requiring moderate concentration) rather than as a deep-drying absorbent (requiring very high concentration). This lower regeneration target simplifies the regeneration system and reduces energy consumption.

Key Design Parameters

Glycol Losses

Glycol losses in an LTS system occur through several mechanisms. Understanding and minimizing these losses is essential for economic operation:

• Vaporization losses: MEG has the lowest vapor pressure of the common glycols, resulting in minimal vaporization loss to the gas phase. At −30°F and 1,000 psig, MEG vaporization loss is typically less than 0.01 gal/MMscf.
• Carryover losses: Glycol droplets entrained in the dry gas leaving the LTS. Controlled by mist extractor design (vane-type or mesh pad). Typical carryover losses are 0.01–0.05 gal/MMscf.
• Solubility losses: MEG dissolves slightly in hydrocarbon condensate. These losses are proportional to the volume of condensate produced and typically represent 0.02–0.10 gal/bbl of condensate.
• Mechanical losses: Leaks, filter changeouts, sampling. Typically the largest loss category and controllable through good maintenance practices.
• Degradation losses: Thermal and oxidative degradation of glycol to organic acids. Minimized by maintaining reboiler temperature below 400°F and using gas blanketing on storage tanks.

Heat Exchanger Approach Temperature Economics

4. Hydrocarbon Recovery Integration

NGL Recovery from the LTS

The hydrocarbon condensate recovered from the low-temperature separator represents a valuable NGL stream. The composition and volume of this stream depend on the inlet gas richness, LTS operating temperature, and operating pressure. At an LTS temperature of −30°F, typical recoveries are approximately 5–15% of the ethane, 40–70% of the propane, 80–95% of the butanes, and essentially 100% of the pentanes and heavier components. These recovery percentages make the combined system competitive with standalone mechanical refrigeration plants for moderate NGL recovery.

NGL Recovery vs. LTS Temperature

Condensate Stabilization

The NGL condensate leaving the LTS is at low temperature and high pressure, containing dissolved light ends (primarily methane and ethane) that will flash upon pressure reduction. A condensate stabilizer column or multi-stage flash system is used to remove these light components and produce a stable liquid product suitable for pipeline transport or truck loading. The stabilizer overhead gas is compressed and returned to the sales gas stream or used as fuel gas.

Gas Shrinkage and Heating Value Impact

Removing heavier hydrocarbons from the gas stream reduces both the volume and heating value of the sales gas. This gas shrinkage must be accounted for in contract gas volume measurements and heating value specifications. For a moderately rich gas (1,100–1,200 BTU/scf inlet), cooling to −30°F may reduce the sales gas heating value to 1,020–1,050 BTU/scf and the gas volume by 3–8%, depending on composition. Pipeline tariff and gas sales contracts often specify a minimum heating value (typically 950–1,050 BTU/scf), which the leaner sales gas will readily meet.

Combined System vs. Separate Systems

The combined system is generally preferred when both dew point specifications can be met at the same LTS temperature, when space and weight are constrained (offshore platforms, FPSOs), or when significant NGL recovery revenue offsets the refrigeration cost. Separate systems are preferred when very deep water dew point depression is required (below −40°F), when the gas is lean and hydrocarbon dew point control is the primary concern, or when operational flexibility to adjust water and HC dew points independently is important.

5. Operational Challenges and Best Practices

Glycol-Hydrocarbon Emulsion Handling

One of the most significant operational challenges in combined glycol/propane systems is the formation of stable glycol-hydrocarbon emulsions in the LTS. At low temperatures, the viscosity of the glycol phase increases and the interfacial tension between glycol and condensate decreases, both of which promote emulsion stability. Contributing factors include fine solids (iron sulfide, formation fines), corrosion products, and naturally occurring surfactants (naphthenic acids, asphaltenes) in the gas stream.

Mitigation strategies include:

• Adequate residence time in the LTS (5–10 minutes for the glycol phase)
• Inlet filtration to remove fine solids before they enter the chilling section
• Coalescing internals (plate packs, coalescing media) in the LTS liquid section
• Chemical demulsifier injection at the LTS inlet when emulsions persist
• Maintaining glycol quality through regular filtration and carbon treatment

Foaming in Glycol Regeneration

Foaming in the glycol reboiler and stripping column reduces regeneration efficiency and can cause glycol carryover into the still column overhead. Foaming is typically caused by hydrocarbon contamination of the glycol, degradation products, or fine solids. The activated carbon filter in the glycol loop is the primary defense against foaming, supplemented by antifoam injection (silicone-based, 5–50 ppm) when necessary. Excessive antifoam use can itself cause foaming and should be avoided.

Salt and Produced Water Effects

Produced water entering the system with the inlet gas often contains dissolved salts (primarily NaCl). When this salty water mixes with glycol and is subsequently heated in the reboiler, salt precipitation can occur, fouling heat transfer surfaces and plugging stripping column packing. Salt management strategies include:

• Effective inlet separation to minimize free water carryover to the glycol system
• A dedicated desalting step (flash at reduced pressure) in the glycol regeneration loop
• Regular monitoring of glycol salt content (target below 1,000 ppm as NaCl equivalent)
• Periodic glycol reclaiming (vacuum distillation or ion exchange) when salt levels exceed operating limits

Glycol Degradation and Reclaiming

Thermal degradation of MEG begins above approximately 400°F, producing organic acids (glycolic acid, formic acid, oxalic acid) that lower the pH of the glycol solution. Low pH accelerates corrosion of carbon steel equipment, particularly in the reboiler and still column. Oxidative degradation occurs when glycol is exposed to air, which is why glycol storage tanks and surge drums should be blanketed with dry gas or nitrogen.

Degradation is monitored by measuring glycol pH (maintain above 7.0, target 7.5–8.5) and total acid number (TAN). When degradation products accumulate beyond acceptable levels, the glycol must be reclaimed. Reclaiming methods include:

• Vacuum distillation: Produces high-purity glycol; removes salts, acids, and heavy organics
• Ion exchange: Removes dissolved salts; often used in combination with distillation
• Side-stream reclaimer: Continuous bleed-and-feed reclaiming; processes 1–5% of circulation rate

Monitoring Parameters

Turndown and Seasonal Operation

The combined glycol/propane system must operate across a range of gas flow rates and ambient conditions. During summer months when ambient temperatures are high, the propane condenser operates at higher pressures and the refrigeration capacity decreases. Conversely, during winter months when inlet gas temperatures are lower, less chiller duty is required but the gas-gas exchanger must be designed to handle potential overcooling scenarios.

Key turndown considerations include:

• Glycol injection rate: Must be reduced proportionally with gas rate to maintain proper glycol-to-water ratio. Excessive glycol injection wastes energy in regeneration and can cause LTS liquid handling problems.
• Refrigeration compressor: Capacity control via slide valve (screw compressor), clearance pockets (reciprocating compressor), or speed control (VFD). Minimum turndown is typically 25–50% of design depending on compressor type.
• LTS separator: At low rates, liquid residence time increases (beneficial for separation quality) but gas velocity decreases (potential for poor mist extraction). Internals should be designed for the full operating range.
• Gas-gas exchanger: At low flow rates, the exchanger effectiveness increases and the cold-end approach temperature decreases. Temperature control on the chiller outlet is used to prevent overcooling.
• Seasonal temperature swings: The LTS target temperature may be adjusted seasonally to match pipeline dew point specifications, which are often less stringent in summer months.

Proper operator training, regular glycol quality monitoring, and preventive maintenance of the glycol regeneration system are essential for reliable long-term operation of the combined glycol/propane dew point control system. Facilities that maintain glycol quality within specification and operate the reboiler at controlled temperatures typically achieve glycol replacement rates of less than 5% of inventory per year, excluding mechanical losses.

References

1. GPSA, Chapter 14 — Hydrocarbon Recovery
2. GPSA, Chapter 20 — Dehydration
3. GPA Standard 2166 — Methods for Obtaining Natural Gas Samples for Analysis by Gas Chromatography
4. Hammerschmidt, E.G. — Formation of Gas Hydrates in Natural Gas Transmission Lines, Industrial & Engineering Chemistry
5. Nielsen, R.B. and Bucklin, R.W. — Why Not Use Methanol for Hydrate Inhibition?, Hydrocarbon Processing