What is HCDP (Hydrocarbon Dew Point)
Principles of HCDP | Why Control HCDP | Specifications for HCDP | Cricondentherm Temperature |
Hydrocarbon Gas Dew Point Curve


Principles of Hydrocarbon Dew Point

Dew point is defined as the temperature at which vapor begins to condense. We see it in action every foggy morning. Air is cooled to its water dew point and the water starts condensing and collects into small droplets. We also see it demonstrated by a cold glass "sweating" on a humid day. The cold glass lowers the air temperature below the water dew point temperature and the water condenses on the sides of the cold glass. Water dew point is relatively simple and easy to predict since it is a single component system. It is easily removed using conventional techniques, primarily TEG (Triethylene Glycol) dehydration units.

Hydrocarbon dew point (HDP) is similar to the water dew point issue, except that we have a multi-component system. Natural gas typically contains many liquid hydrocarbon components with the heavier components found in smaller amounts than the lighter gaseous ends. It is the heaviest weight components that first condense and define the hydrocarbon dew point temperature of the gas. The dew point temperature also moves in relation to pressure.

One of the first questions we are asked by producers with a hydrocarbon dew point issue is:

"How can my hydrocarbon dew point be so high?"

In return, we ask the producer at what temperature does his high-pressure production separator operate? By definition, a production separator separating oil from gas operates at vapor-liquid equilibrium. Therefore, the gas leaving the separator is in equilibrium with the oil. In other words, the gas leaving the separator is at its hydrocarbon dew point that equals the separator operating temperature (and pressure.) If the separator is operating at 100°F, then the gas has a 100°F dew point at separator pressure. As the gas leaves the separator and cools flowing through the piping system, liquids condense and the dew point decreases as the heavy ends condense. The TEG dehydration unit will remove some heavy hydrocarbons, in addition to water, and further reduce the hydrocarbon dew point. At the sales meter, (without a conditioning unit) the hydrocarbon dew point is usually close to the lowest temperature the gas has achieved on the location before it was sampled, at operating pressure.

Why Control Hydrocarbon Dew Point?

The gas transportation companies have come to the realization that managing hydrocarbon dew point reduces system liabilities, opens up new gas markets and generates operating revenue. By managing hydrocarbon dew point, hydrocarbon condensation can be prevented in cold spots under rivers and lakes where the liquids collect in the low areas and then often move as a slug through the system, over pressuring the pipe, and overpowering liquid handling facilities, flowing into compressors and end user sales points.

Most importantly, liquids in burners and pilots onsite and at end user locations at LDCs, can cause fire and explosion hazards. Also, removing pipeline liquids helps prevent pipe corrosion in the low areas where water is trapped under the hydrocarbon liquid layer and slowly destroys the pipe integrity. Proper managing of gas dew point can also prevent liquids from forming as the gas cools while flowing through pressure reduction stations (e.g. citygates) that feed end user supply systems. Controlling dew point is also necessary to qualify the pipeline to market gas to high efficiency gas turbine end users that require a dry and consistent quality fuel.

Specifications for HDP

Pipelines use two main methods to specify contractual natural gas hydrocarbon dew points.

  1. Limit on C5+ or C6+ components by analyzing for:
    • GPM (gallons of liquid per thousand SCF)
    • Mole %
  2. Specifying an actual HDP by:
    • Setting a hydrocarbon dew point temperature maximum at operating pressure
    • Setting a maximum cricondentherm hydrocarbon dew point

In addition, typical pipeline specifications, or tariffs, almost always specify a maximum GHV (Gross or Higher Heating Value), which is greatly affected by heavy hydrocarbons contained in the gas stream.

Cricondentherm Temperature

The cricondentherm temperature is the highest dew point temperature seen on a liquid-vapor curve for a specific gas composition over a range of pressure, e.g. 200-1400 psia. When you look at a hydrocarbon gas dew point temperature curve (phase envelope,) the curve bends with pressure. Shown below is a dew point curve, after conditioning, for a south Texas gas analysis. The transporting pipeline requires a 20°F cricondentherm temperature. At the time this sample was taken, the cold separator on the gas conditioning equipment was operating at 9°F and 875 psig.

Hydrocarbon Gas Dew Point Curve

Dew Point Temperature
Pressure
F
PSIA
9.0°
200
12.9°
250
15.6°
300
17.5°
350
18.8°
400
19.5°
450
19.7°
500
Cricondentherm
19.6°
550
19.1°
600
18.2°
650
17.0°
700
15.4°
750
13.5°
800
11.1°
850
Operating at 9°F and 875#
8.5°
900
5.2°
950
1.4°
1000
-3.3°
1050
-9.4°
1100
-18.7°
1150

The temperature shown in the HDP curve represents the gas dew point at the corresponding pressures.

A cricondentherm specification at first seems like the best way a pipeline can protect its assets. The transporting pipeline operator knows if it sets a cricondentherm temperature restriction below the lowest temperature seen in its system, it can raise and lower the gas pressure in the pipeline transportation system, and not have to worry about liquid condensation.

The problem a pipeline operator has in using a cricondentherm specification is in the calculation of the cricondentherm temperature. The cricondentherm temperature is calculated by obtaining an extended gas analysis and then inputting the analysis data into a software package, using equations of state to predict the dew point temperatures at the range of pressures.

However, many gas-transporting companies tend to collect gas composition data using on-line chromatographs or composite samples with a grouped C6+ component. The C6+ component does not provide any information on the heavier hydrocarbon (C7+) components that determine the gas hydrocarbon dew point. To calculate a cricondentherm the pipeline operator must make some assumptions. It is these assumptions that are causing problems. The pipeline operator must decide how to distribute the C6+ component for his calculation. The most commonly used distribution assumptions are the Daniels/El Paso distribution (i.e. 48% C6; 35% C7; 17% C8+) and the GPA distribution (i.e. 60% C6, 30% C7, 10% C8+). If the Daniels distribution shown in the previous sentence is used on the gas represented in the dew point curve above, the cricondentherm dew point calculates to be 38.1°F, which is 18.4°F higher than its actual cricondentherm temperature. The producer would need to operate his cold separator on his conditioning unit at -10°F (negative 10°F) to meet the system requirements due to the assumptions made in calculating the gas cricondentherm. Another popular mistake is to perform an analysis that groups the C6, C7 and C8+ components, rather than using the detailed component-by-component breakdown. Grouping also skews the cricondentherm. If you group the above components, the cricondentherm calculates at 32.6°F or 12.9°F high. It is DPC's experience that grouping will add a minimum of 3°F to 5°F to the calculated cricondentherm temperature.

To be useful in a commercial environment, pipeline hydrocarbon dew point specifications must be easily measured with existing equipment. The majority of the transporting pipeline systems measure using a C6+ component system. These systems can be used to track cricondentherm based specifications as long as the heavier components are not distributed arbitrarily.

DPC does not recommend detailed analysis be taken beyond C8+ on dew point conditioned gas streams as it is not useful and results in unnecessary expense.