Hydrocarbon Dew Point

The hydrocarbon dew point, abbreviated HDP or HCDP, is the temperature at which the hydrocarbon components of a gas mixture, most often natural gas, begin to condense into liquid at a given pressure. Above that temperature the gas stays entirely gaseous. Cool it below the dew point, or in some cases change its pressure, and droplets of liquid hydrocarbon start to form.

That sounds like a narrow technical property, but it shapes a great deal of how the natural gas industry works. Liquids forming in a pipeline can damage compressors, upset flow meters, block pressure regulators and reach customers' burners and turbines. As a result, the hydrocarbon dew point is written into gas contracts and pipeline tariffs, measured continuously at processing plants and border points, and debated by regulators. It is one of the main reasons raw natural gas is processed before it reaches the pipeline grid.

This article explains what the hydrocarbon dew point is, how it relates to the phase behavior of gas mixtures, why it matters, how specifications developed, how the dew point is measured and calculated, and where the uncertainties lie.

Definition

The international vocabulary standard for natural gas, ISO 14532, defines the hydrocarbon dew point as the temperature above which no condensation of hydrocarbons occurs at a specified pressure. Two notes attached to that definition, quoted in a 2007 report by the UK's National Physical Laboratory, add the essential context. At a given dew point temperature there is a range of pressures within which retrograde condensation can occur, and the cricondentherm is the maximum temperature at which such condensation can occur. The dew point line is the set of pressure and temperature points that separates single-phase gas from the two-phase gas-liquid region.

Three features of the definition are worth drawing out:

It depends on pressure. A hydrocarbon dew point quoted without a pressure is incomplete. The same gas has different dew points at different pressures.
It depends on composition. The heavier hydrocarbons in the mixture, especially hexane and anything heavier, have by far the largest influence.
It is not the water dew point. Natural gas also carries water vapor, which has its own dew point. The two are separate properties and are measured and specified separately.

The Wikipedia article adds that the hydrocarbon dew point is a key quality parameter written into contracts and enforced all the way from producers through processing, transmission and distribution to final users.

Phase behavior of gas mixtures

Pure substances versus mixtures

A pure substance such as water or methane has a single boiling temperature at each pressure. At that temperature, vapor and liquid can coexist; above it, the substance is all vapor; below it, all liquid. On a pressure-temperature chart, the boiling points trace out a single curve.

A mixture of many substances is different. Its components boil at different temperatures, so instead of a single line there is a region of two-phase behavior, bounded on one side by a bubble point curve, where the first bubble of vapor appears in a cooling liquid, and on the other side by a dew point curve, where the first drop of liquid appears in a cooling gas. Together these form a closed loop called the phase envelope.

The phase envelope

Natural gas is mostly methane, with smaller amounts of ethane, propane, butanes, pentanes and heavier hydrocarbons, plus non-hydrocarbon gases such as nitrogen and carbon dioxide. Its phase envelope has a characteristic shape, described in detail in the Natural Gas Council's 2005 white paper on liquid hydrocarbon drop out:

The dew point curve rises from low pressure to a maximum temperature and then bends back toward lower temperature at higher pressures.
The critical point is where the bubble point and dew point curves meet.
The cricondenbar is the maximum pressure at which liquid and gas can coexist.
The cricondentherm is the maximum temperature at which liquid and gas can coexist. Above this temperature, the gas cannot form hydrocarbon liquid at any pressure.

Term	Meaning	Why it matters
Dew point (at pressure P)	Temperature at which liquid first appears at pressure P	Tells whether gas at a specific point in the system will stay single-phase
Cricondentherm	Highest temperature at which two phases can coexist	A single number that guarantees no hydrocarbon liquid at any pressure if the gas is kept warmer
Cricondenbar	Highest pressure at which two phases can coexist	Above it, the fluid behaves as a dense single phase
Critical point	Meeting point of bubble and dew curves	Divides bubble point behavior from dew point behavior

Retrograde condensation

The most counterintuitive part of the phase envelope is retrograde condensation. For a pure substance, raising the pressure or lowering the temperature promotes condensation. In the region of the gas mixture's phase envelope between the critical point and the cricondentherm, lowering the pressure at constant temperature can actually cause liquid to form. The NGC white paper explains that the word "retrograde" means moving backward, and that the phenomenon got its name because it runs contrary to the behavior of pure components.

This matters for pipelines because gas pressure falls at regulators and valves. A gas that is safely outside its two-phase region at high pressure can drop into it when its pressure is reduced, especially since pressure reduction also cools the gas.

The Joule-Thomson effect

When gas expands through a valve or regulator without doing work, its temperature changes. For natural gas under typical pipeline conditions, it cools. The NGC white paper gives a rule of thumb used in pipeline engineering: about 7 °F of temperature drop per 100 psi of pressure reduction. Engineers draw a line of this slope on the phase diagram, called the J-T line, to see whether gas passing through a pressure reduction will enter the two-phase region.

Why the hydrocarbon dew point matters

In pipelines and distribution networks

The NGC white paper lists the operational problems that hydrocarbon liquids cause when they form in transmission and distribution systems:

Damage to or poor performance of compressors.
Errors in gas measurement, since most meters are designed for single-phase gas.
Malfunction of pressure regulation and over-pressure protection devices.
Possible interference with odorization, the process that gives naturally odorless gas its warning smell.

The paper also explains how pipelines historically coped with small amounts of liquid: drips, which are vessels attached to the pipeline that capture liquid by impingement or gravity. The liquids collected are periodically removed and either recovered as fuel, where allowed, or disposed of as hazardous waste, which can raise operating costs dramatically. Drips themselves can corrode, and the paper notes that the Office of Pipeline Safety had in some cases required or encouraged operators to remove them since the late 1990s.

For end users

Liquid hydrocarbons reaching customers cause their own trouble. The NGC paper mentions flame extinguishing or over-firing in home appliances and physical damage to gas turbines used for power generation. A Michell Instruments technical article adds that dew point control helps power generators keep nitrogen oxide emissions within limits and protects turbines from flashback.

For gas storage and LNG

Underground storage operators and operators of liquefied natural gas (LNG) peak-shaving plants also care about the dew point. The NGC paper notes that LNG peak-shaving liquefaction plants receiving feed with an excessive hydrocarbon dew point can suffer heat exchanger fouling and collect more liquids than they are designed to handle.

For commerce

Natural gas moving through open-access pipelines is treated as fungible: one shipper's gas can be swapped for another's. That only works if all the gas meets common quality limits. A shipper who sends rich, wet gas into a line affects every downstream user, so pipelines set quality specifications at receipt points, including limits that control hydrocarbon liquid drop out.

Where heavy hydrocarbons come from

Types of natural gas

The NGC white paper describes three main sources of natural gas:

Source	Description	Typical liquid content
Associated gas	Produced along with oil and separated at the lease	Traditionally very rich in natural gas liquids
Non-associated gas	From fields that do not produce oil	Generally leaner
Coal bed methane	From coal seams after de-watering	Usually no liquid hydrocarbons; may carry CO₂, O₂ and water

Natural gas liquids, or NGLs, are defined in the paper as ethane, propane, butanes, and pentanes plus heavier hydrocarbons. The pentanes-plus fraction is commonly called natural gasoline. Gas rich in NGLs has a high heating value and a high hydrocarbon dew point.

Rich gas, lean gas and GPM

The industry describes gas richness with the terms "rich" and "lean," and quantifies it in GPM. In US usage, GPM means gallons of liquefiable hydrocarbons per thousand cubic feet of gas at stated temperature and pressure. Wikipedia notes the conventions:

For raw produced gas, GPM is usually reported as GPM (C2+), ethane and heavier, or GPM (C3+), propane and heavier.
For processed pipeline gas, it is reported as GPM (C6+), hexane and heavier.

Wikipedia warns that these two uses must not be confused, and that GPM and hydrocarbon dew point are not interchangeable. GPM measures how much liquid could be recovered; dew point measures the temperature at which liquid first appears.

The NGC paper describes how GPM is calculated for an individual component: take the component's mole fraction, divide by a volume constant giving cubic feet of ideal gas per gallon of liquid, from GPA Standard 2145, and multiply by 1,000 to express the result per thousand standard cubic feet.

History: processing and the falling dew point

Before processing

The NGC paper gives a rare historical sketch. Before gas processing developed, hydrocarbon dew points in pipelines and market areas approached ambient temperatures, between 30 and 60 °F. Pipelines simply collected liquids and developed their own ways of forcing them out of the gas before delivery.

Compression and refrigeration

The first processing plants were essentially compression plants. They compressed casinghead gas, the gas from oil wells, and cooled it with air or water exchangers to condense the heavy NGLs. According to the paper, this recovered about 25 percent of the hexanes-plus and lowered the cricondentherm to about 10 °F at the plant outlet.

After 1940, propane became available as a refrigerant, as demand for butane in motor gasoline increased and rural heating switched from butane to propane during the 1940s and 1950s. Refrigeration plants dropped the cricondentherm at the plant outlet from about 80 °F to slightly above 0 °F, recovering half or so of the propane and 80 percent or more of the butanes-plus. The gas being processed was very rich casinghead gas, about 1,200 to 1,400 Btu per cubic foot and 4 to 7 GPM.

Lean oil and cryogenic plants

In the early 1960s, as ethane became valuable, lean oil absorption plants were built in new oil and gas regions. They recovered more than 70 percent of the propane and 90 percent of the butanes-plus, producing gas with a cricondentherm of −30 °F or lower.

After the 1972 oil embargo, high oil prices made it worth recovering nearly all the NGLs. Cryogenic processing became economical, recovering between 60 and 99 percent of the ethane, depending on technology, and essentially all of the propane-plus, producing cricondentherms of −100 °F or lower. Cryogenic technology was retrofitted at many older plants in the late 1970s.

Offshore, the paper notes that the Minerals Management Service eliminated routine flaring of gas on the Outer Continental Shelf in the late 1950s, which led to a pipeline construction boom and large straddle plants to process formerly flared associated gas.

Summary of the processing eras

The NGC paper summarizes the approximate cricondentherm achievable at the plant outlet in each era:

Era	Processing technology	Approximate achievable cricondentherm
1940–60	Refrigeration	0 °F
1960–75	Lean oil	−10 °F
1975 on	Cryogenic	−100 °F

The paper stresses that the actual cricondentherm in any pipeline depends on the mix of processed and unprocessed gas and how deeply the processed gas was treated.

Processing to control the dew point

By the 2000s, economics had shifted again. When natural gas prices are high relative to NGL prices, producers have less reason to strip out liquids and may reduce extraction or bypass processing. The NGC paper describes new plants designed to minimize recovery of the lightest hydrocarbons, methane through propane, while still lowering the dew point, mainly using refrigeration, short-cycle adsorption with molecular sieves, and Joule-Thomson skids.

The paper puts the commercial tension plainly. When suppliers process less, more liquefiable hydrocarbons stay in the gas, and the risk of liquid drop out in transit rises. That tension, more than any technical question, drove the push for clearer dew point specifications.

Specifications and regulation

In the United States

US interstate pipeline tariffs are filed with the Federal Energy Regulatory Commission. The NGC paper notes that many tariffs still contain a phrase that originated in an older industry document: gas shall be "commercially free from dust, gum, gum forming constituents, and liquids at the pressure and temperature at which the gas is delivered." Historically, pipelines handled hydrocarbon content in many different ways, and there has never been a common US specification for it in the way there is broad agreement on limits for water, carbon dioxide and hydrogen sulfide.

Some pipelines used heating value limits. The NGC paper explains why that is inadequate: a gas can have relatively low heating value and still contain enough hexanes-plus to have a high dew point, while a gas rich in ethane can have high heating value but a low dew point. Other pipelines set C5+ GPM, C5+ mole percent, or C6+ GPM limits. More recently, operators began setting direct dew point limits. As of June 2004, eleven interstate pipelines had approved tariff hydrocarbon dew point limits and three more had proposed them.

The Natural Gas Council white paper

In 2005, an industry group called the NGC+ Liquid Hydrocarbon Drop Out Task Group published a white paper dated February 28, 2005. It reached several technical conclusions:

The C5+ approach and the heating value approach were not effective at predicting and controlling liquid drop out and should not be used as control parameters.
Both the cricondentherm hydrocarbon dew point (CHDP) and a C6+ GPM limit were valid control parameters.
Calculating either one should use an equation of state with data from gas chromatography.
The CHDP offered the greatest operational flexibility for all stakeholders.
A C6+ GPM limit alone would not give end users all the information needed to design and operate their equipment outside the two-phase region.
Pipeline operators using either method should periodically validate their assumptions about the proportions of C6, C7, C8 and heavier components.
Determining HDP with the Bureau of Mines manual method was not practical for automated applications.

The paper also listed the factors to consider when setting a limit, including minimum flowing gas temperature, minimum ambient air and ground temperatures, operating pressures, pressure reductions, the dew points of gas supplied, experience with liquid problems, the presence of heaters and separators, flow patterns, storage, end-user applications and LNG peak-shaving feed requirements.

FERC's 2006 policy statement

In June 2006, FERC issued a policy statement on natural gas quality and interchangeability. It endorsed the NGC+ interim guidelines as a starting point where a pipeline did not already have acceptable provisions in its tariff, but did not make them mandatory. A legal summary published on the Project Finance law site in September 2006 described FERC's approach as case by case rather than uniform national standards, with tariffs to be developed by pipelines together with their customers, grounded in technical analysis, and with significant weight given to the NGC reports.

Individual pipelines then set their own limits. Trade press reported, for example, that FERC approved a contested settlement establishing a CHDP safe harbor level of 15 °F on Tennessee Gas Pipeline.

In Europe

European gas transmission developed differently, with cross-border trade encouraging harmonization. In 2005, the European Association for the Streamlining of Energy Exchange-gas (EASEE-gas) agreed harmonized gas quality values in Common Business Practice 2005-001/01. Its hydrocarbon dew point limit is −2 °C at pressures from 1 to 70 bar. That value is cited in ISO/TR 11150:2007 and in a 2006 Gasunie paper, which also notes that European measurements are usually made at 25 to 30 bar, the range in which liquid drop out occurs at the highest temperatures.

Comparing the two approaches

Aspect	US practice (post-2005)	European practice
Who sets limits	Individual pipelines in FERC-approved tariffs	Harmonized business practice plus national rules
Typical parameter	Cricondentherm HDP or C6+ GPM	Dew point at pressures from 1 to 70 bar
Example value	CHDP safe harbor of 15 °F on one pipeline	−2 °C from 1 to 70 bar (EASEE-gas)
Measurement norm	Indirect GC calculation common; manual ASTM D1142 devices still used	Automated instruments widespread; ISO/TR 12148 for calibration

Measuring and calculating the dew point

There are two broad routes to a hydrocarbon dew point. The direct route cools a surface in contact with the gas until liquid appears. The indirect route analyzes the gas composition and calculates the dew point using thermodynamics.

The direct method: chilled mirrors

A chilled mirror instrument passes gas over a polished surface that is cooled steadily. When hydrocarbon liquid condenses on the mirror, the temperature is recorded.

Manual instruments. The traditional device in North America is the Bureau of Mines dew point tester, which conforms to ASTM D1142, a standard written for water dew point that is also used for hydrocarbons. An operator watches the mirror and judges when condensation appears. Wikipedia notes that this is subjective and that operators tended to under-report the dew point, because a hydrocarbon film is thin and hard to see. The NGC white paper calls for development of a cost-effective direct-reading analyzer because manual instruments are subject to operator variability and interference, including from water vapor.

Automated instruments. Automated chilled mirror devices detect condensation optically, by changes in light reflected from the mirror. Wikipedia names suppliers including Vympel, Ametek, Michell Instruments and Bartec Benke, and mentions spectroscopic analyzers and laser interferometry as newer variants that reduce the effect of mirror contamination. A current Michell product page quotes an accuracy of ±0.5 °C for its automated hydrocarbon dew point measurement, using a semiconductor-grade silicon mirror with an integrated PT1000 temperature element and camera-based detection of color changes in the reflected image.

Limits of the direct method. Several issues are built into the technique:

Condensation must happen before it can be seen, so measured dew points are lower than theoretical values.
Results depend on how fast the mirror is cooled and when detection is triggered.
The instrument measures the dew point only at the pressure of the sample cell. Wikipedia notes that natural gas cricondentherms typically occur around 27 bar, and some systems regulate inlet pressure to that value; the NPL report says 27 bar gauge is the usual pressure for field measurements in the UK.
Mirror contamination can confuse detection.

The indirect method: gas chromatography and equations of state

The indirect method has three steps, as the NGC white paper explains: take a representative sample, analyze its composition with a gas chromatograph (GC), then calculate the dew point with an equation of state.

Equations of state. An equation of state relates pressure, temperature and density for a fluid mixture. The two most common in the gas industry are the Peng-Robinson equation, published by Peng and Robinson in 1976, and the Soave-Redlich-Kwong equation, published by Soave in 1972. Both are cubic equations with parameters for each component.

The trouble with the heavy end. A typical field GC reports methane through pentanes individually and lumps everything heavier into a C6+ group. But the dew point is extremely sensitive to exactly what is in that heavy group. The NGC paper explains that a C6+ fraction must be "split" into assumed proportions of C6, C7 and C8 before calculation. A commonly published split, 60/30/10 from a GPA standard, tends to underestimate dew points and cricondentherms. Work by a chromatograph manufacturer suggested a 47:36:17 split as more generally applicable, though it varies with gas source and processing. The paper also warns that as little as 0.001 mole percent of C9 can have a significant effect on the calculated dew point.

Error sources. Wikipedia groups the errors in the indirect method into four categories:

Error source	What goes wrong
Sampling	Pressure reduction during sampling can drop heavy components out of the gas, especially in the retrograde region
Analysis	A field GC with about 2% of range error, at a 0 to 1 mol% range for C6, gives about 0.02 mol% uncertainty; C6+ errors can shift the dew point by 100 °F or more; independent studies cite cumulative errors above 30 °C
Calibration	Calibration gas must be representative and applied routinely
Equation of state	Different models diverge, sometimes significantly

Extended analyses help. A C9+ GC reduces the heavy-end uncertainty, and a laboratory C12+ GC with a flame ionization detector reduces it further, though at the cost of extra sampling and lag-time error.

Advantages. The indirect method has one big advantage: a single analysis yields the entire phase envelope, including the dew point at any pressure and the cricondentherm. Wikipedia lists practical uses that follow from this, such as identifying the phase of the stream at a flow meter, detecting ambient temperature effects in the sample system, and avoiding amine foaming in gas treating contactors.

Potential hydrocarbon liquid content

A related measurement, defined in ISO 6570, is the potential hydrocarbon liquid content: the mass of hydrocarbon liquid per unit volume of gas that would condense at a given temperature and pressure. It addresses a practical question the dew point alone cannot answer. As the NGC paper puts it, a sample containing 0.001 mole percent of C10 may have a relatively high dew point, but the volume of liquid formed will not affect pipeline operations. Knowing how much liquid forms can matter more than knowing exactly when the first drop appears.

Combining the methods

Because direct and indirect methods have different weaknesses, combining them can help. Wikipedia describes the approach of pairing a C6+ GC analysis with one experimental dew point at any pressure to build a more exact phase diagram. The NGC paper mentions a similar hybrid being evaluated in its time, and calls for more research to improve agreement between direct and indirect methods.

How well do the methods agree?

The NPL comparison

The best-known independent comparison is NPL Report AS 3, "Comparison of methods for the measurement of hydrocarbon dew point of natural gas," published in May 2007 by A. Brown, M. J. T. Milton, G. M. Vargha and colleagues from NPL, EffecTech, Michell Instruments, Orbital, National Grid and Advantica, with funding from the UK Department of Trade and Industry. It tested six methods: one automatic chilled mirror instrument, one manual chilled mirror instrument, two laboratory GCs and two process GCs, on both synthetic and real natural gases.

Synthetic gases

For synthetic mixtures of known composition, the report found:

The dew points from Lab GC 1 agreed with those calculated from the gravimetric (weighed-in) composition to within an average of 0.3 °C at the cricondentherm.
The automatic chilled mirror agreed with the gravimetric data to within an average of 1.9 °C, within the measurement uncertainty.
When the automatic chilled mirror was compared with the theoretical temperature at which 70 mg/m³ of condensate forms, the average difference fell to 0.7 °C. That condensate level corresponded roughly to the instrument's detection sensitivity setting of 275 mV, and the report notes it is equivalent to about 10 μmol/mol of n-decane, 11 μmol/mol of n-nonane or 14 μmol/mol of n-octane.

The study also checked how much the choice of equation of state matters. For one real gas, the Peng-Robinson equation gave a cricondentherm more than 2 °C lower than the Soave-Redlich-Kwong equation and a related model, because it overestimates the vapor pressure of heavier components. That 2 °C gives a sense of the uncertainty from model choice alone.

Real gases

Real gases proved harder. The table shows dew points determined by the four GC methods for seven real gases, at a pressure at or near each gas's cricondentherm, as reported in the NPL study.

Gas	Pressure (bar)	Lab GC 1 (°C)	Lab GC 2 (°C)	Process GC 3 (°C)	Process GC 4 (°C)
A	50	7.4	6.8	6.8	5.4
B	35	−8.4	−9.7	−10.0	−7.5
C	30	−1.1	−1.6	−3.1	−1.7
D	40	−3.7	−4.8	−5.7	−6.2
E	45	−37.6	−37.5	−37.8	−36.1
F	35	−23.7	−24.5	−24.7	−23.5
G	15	−26.4	−40.1	−63.5	−51.2

For the first three GCs, the dew points fell in the same order in every case, with Lab GC 1 highest and Process GC 3 lowest. The report attributes that to the instruments' differing sensitivity to heavy components: the better an instrument sees the heavy end, the higher the calculated dew point. Excluding Gas G, which had a highly unusual composition, the GC methods agreed within 2.5 °C at the cricondentherm.

The chilled mirror instruments varied more. Comparing the automatic and manual instruments at the same pressures, the manual readings were consistently lower. For example, Gas B read −6.5 °C on the automatic mirror and −12.5 °C on the manual one, and Gas F read −19.8 °C and −27.5 °C. That pattern fits the long-standing observation that manual operators under-report.

What the study concluded

The NPL report concluded that a "true" hydrocarbon dew point is difficult both to measure and to define, that the measured value depends on the method, and that any reported dew point should state the analytical method used. It also concluded that accurate synthetic gas mixtures are essential for calibrating GCs, but play a more limited role for chilled mirrors. A standard of n-butane in nitrogen is cheap and simple for checking chilled mirror temperature sensors, but it forms an unusual, rapidly condensing film unlike that from real gas.

Worked examples

Example 1: pressure reduction at a regulator

This example is hypothetical and uses the NGC rule of thumb of about 7 °F of cooling per 100 psi of pressure drop.

Gas arrives at a city-gate regulator at 60 °F and 1,000 psi and is reduced to 400 psi. The pressure drop is 600 psi, so the gas cools by roughly:

600 ÷ 100 × 7 °F ≈ 42 °F

The gas leaves the regulator at about 60 − 42 = 18 °F. If the pipeline's tariff limited the cricondentherm to 15 °F, the gas would remain just outside the two-phase region with a margin of only about 3 °F. On a cold day with lower inlet temperature, or with gas at the upper edge of its specification, liquid could form. This is why operators install gas heaters ahead of large pressure reductions and why the NGC paper includes pressure reductions among the factors in setting a limit.

Example 2: the NGC curve fit

This example applies one specific correlation and should not be generalized.

The NGC white paper describes a set of 55 unprocessed receipt-point samples for which dew points and C6+ GPM values were calculated using the Peng-Robinson equation of state and a 40/40/20 C6/C7/C8 split. A simple curve fit relating them was:

HDP (°F) = 392 × (C6+ GPM)^0.159 − 210

Plugging in a few values gives:

C6+ GPM	Calculated HDP (°F)
0.01	about −21.5
0.02	about 0.5
0.05	about 33.5
0.10	about 61.8

Two lessons stand out. First, the dew point rises steeply at low GPM levels: going from 0.01 to 0.05 GPM raises the calculated dew point by more than 50 °F. Tiny amounts of heavy hydrocarbons matter a great deal. Second, the correlation was fitted to one data set with one set of assumptions. A different region, a different split or a different equation of state would give different constants. The NGC paper offers it as a demonstration of how a pipeline can relate gas quality to flow volumes, not as a universal formula.

Example 3: converting units

This example uses exact unit conversions.

The EASEE-gas limit of −2 °C converts to about 28.4 °F (−2 × 9/5 + 32). The US safe harbor of 15 °F converts to about −9.4 °C ((15 − 32) × 5/9). The European limit applies across a pressure range of 1 to 70 bar, which is roughly 14.5 to 1,015 psi, while the US value is a cricondentherm limit that by definition covers all pressures. Because the two limits are defined differently, comparing them as numbers alone can mislead.

Common misconceptions

"Hydrocarbon dew point and water dew point are the same thing." They are separate properties. Water vapor and hydrocarbon vapor condense independently, have separate specifications, and are measured by separate methods, though a chilled mirror can sometimes see both and confuse them.

"A dew point is a single number for a gas." A dew point is only meaningful at a stated pressure. The cricondentherm is the one pressure-independent figure, which is why specifications often use it.

"GPM and dew point measure the same thing." Wikipedia stresses that they are not interchangeable. GPM measures how much liquid could form; dew point measures when it starts to form.

"Heating value tells you whether liquids will drop out." The NGC paper found heating value an inadequate predictor. A gas with modest heating value and a high hexanes-plus content can have a high dew point.

"A chilled mirror gives the true dew point." It gives the temperature at which the instrument detected a film, which is lower than the theoretical dew point. Manual instruments typically read lower still. The NPL study concluded that the measured value depends on the method.

"GC calculation is exact because it is computed." The result is only as good as the sample, the detection of heavy components, the split assumptions and the equation of state. Errors in the heavy end can shift the result by tens of degrees.

"Retrograde condensation is rare." It is a normal feature of natural gas phase behavior between the critical point and the cricondentherm, and it is exactly the region that matters when gas pressure drops at regulators.

Frequently asked questions

What is the hydrocarbon dew point in simple terms?

It is the temperature at which hydrocarbon vapors in a gas start to turn into liquid droplets at a given pressure. Keep the gas warmer than that and it stays all gas.

What is the cricondentherm?

The highest temperature at which liquid and gas can coexist for a given mixture. If gas is kept above its cricondentherm, no hydrocarbon liquid can form at any pressure.

Why do pipelines care?

Liquids damage compressors, upset meters and regulators, may interfere with odorization, and can cause problems in home appliances and gas turbines. They also have to be collected and disposed of, sometimes as hazardous waste.

What limits are used?

In Europe, EASEE-gas sets −2 °C at pressures from 1 to 70 bar. In the US, each pipeline sets its own limit in its tariff, often as a cricondentherm; one reported example is a 15 °F safe harbor on Tennessee Gas Pipeline.

At what pressure is the dew point usually measured?

Typically around 27 bar, where the cricondentherm of many natural gases lies. The NPL report describes 27 bar gauge as the usual field pressure in the UK, and a Gasunie paper cites 25 to 30 bar in European practice.

Which method is better, chilled mirror or GC?

Each has strengths. Chilled mirrors measure directly but only at one pressure, and their readings depend on detection sensitivity and the operator or optics. GC calculations give the whole phase envelope but depend heavily on heavy-component analysis and model choice. The NPL comparison found the GC methods agreed with each other within 2.5 °C on most real gases, while chilled mirrors varied more.

How is a high dew point fixed?

By processing: cooling the gas to condense heavy hydrocarbons and separating the liquid. The NGC paper names refrigeration, short-cycle molecular sieve adsorption, and Joule-Thomson expansion skids as the common technologies for dew point control.

Which standards apply?

ISO 14532 defines the term. ISO 6570 covers potential hydrocarbon liquid content. ISO 23874 sets gas chromatographic requirements for dew point calculation. ISO/TR 12148 covers calibration of chilled mirror instruments. ASTM D1142 is the reference for manual instruments in North America. ISO/TR 11150 discusses hydrocarbon dew point and hydrocarbon content more broadly.

Summary

The hydrocarbon dew point captures a simple idea, the temperature at which a gas begins to rain hydrocarbon droplets, but it rests on the complicated phase behavior of mixtures. Natural gas has a phase envelope rather than a boiling point, with a cricondentherm that sets the warmest temperature at which liquid can ever form and a retrograde region in which pressure drops can trigger condensation.

Over the twentieth century, gas processing pushed pipeline dew points from near ambient temperatures down to well below zero Fahrenheit. When the economics of processing changed in the 2000s, the industry and regulators turned to explicit dew point limits, recommended by the Natural Gas Council in 2005, endorsed as a starting point by FERC in 2006, and harmonized in Europe at −2 °C from 1 to 70 bar. Measuring the dew point remains surprisingly hard. Chilled mirrors and gas chromatographs give different answers for real reasons, and the best practice is to state the method alongside any value and to understand its uncertainties.