The measurement of hydrocarbon dew point (HCDP) has a significant impact on the bottom line, pipeline efficiency and maintenance requirements for a natural gas company.
When high energy hydrocarbons drop out of the gas phase into the liquid phase, they increase pipeline operational costs and reduce BTU content of the gas phase, which leads to energy loss. The hydrocarbon dew point is used to determine the temperature at which no condensation of the hydrocarbons occurs at a specific pressure — basically the temperature in which hydrocarbon dropout will not occur in
The increased use of nontraditional sources of natural gas and the interconnecting web of pipelines have increased the potential of richer gas streams flowing in pipelines that previously carried leaner natural gas. Richer gas streams have a higher likelihood for hydrocarbon liquids to form in the gas stream, which can cause hydrate formation, increase compression costs, cause issues with pressure regulator freezing and lead to damage to end-user equipment such as gas turbines.
As a result, custody transfer agreements frequently specify HCDP limits and require reporting of such at the custody transfer locations. Because of these transmission and pipeline operational issues, HCDP measurement has become critical, standard and generally required in the natural gas industry. While there are devices that have traditionally been used to measure HCDP, today many natural gas companies are finding that using a gas chromatograph (GC) to measure HCDP can save time and money.
What is Hydrocarbon Dew Point?
Hydrocarbon dew point is the temperature at a defined pressure at which hydrocarbon liquids begin to form. For natural gas pipeline operators, this can be translated to mean the temperature at which liquid condensates begin to appear in their pipelines.
Figure 1 shows a meter run that still had condensate in it after it had been de-pressured and opened up for inspection. Clearly, the gas flowing through the pipe had a hydrocarbon dew point much higher than the flowing temperature, resulting in the heavy components “dropping out” and forming a puddle on the bottom of the pipe. In the United States, this condensate is often referred to as “drip.” It is important to remember that this is hydrocarbon dew point — not moisture dew point which is when water starts to drop out.
The hydrocarbon dew point changes with pressure, but it is not a linear relationship. Figure 2 shows the hydrocarbon dew points at different pressures to show the “dew curve.” The temperature at which condensate begins to form changes dramatically with pressure. Any condition to the right of the dew curve indicates the mixture will be completely in the gas, or vapor, phase.
A condition to the left of the dew curve indicates the mixture will be two-phase — a mixture of vapor and liquid. The point on the curve which has the highest hydrocarbon dew point is called the cricondentherm. This is sometimes referred to in pipeline tariff agreements as the highest dew point at any pressure and is often the value that is reported as a part of the gas quality measurement.
In looking at the typical pipeline transmission pressure and the typical distribution network pressure, the cricondentherm lies in between the two. If there is a pure vapor phase in the transmission pipeline, when the pressure is reduced at a city-gate pressure reduction station, the mixture may pass through the dew curve and form liquids. This causes all sorts of operational issues including regulator freeze-ups.
Why Measure Hydrocarbon Dew Point?
Measuring hydrocarbon dew point is required for tariff assessments and to meet contractual obligations, but there are also important additional benefits that natural gas pipeline companies can achieve by the accurate measurement of HCDP. These include cost savings from reduced wear on equipment, enhanced efficiency and lowered maintenance requirements.
Operational costs increase when hydrocarbon liquids are present. When condensate liquids form in the pipelines, the lines need to be pigged and the hydrocarbon liquids need to be collected and processed, all driving up costs. In addition, compression costs increase since it’s harder to push liquid than gas through the pipelines.
When hydrocarbon liquid is present, there is also greater wear on compressors, valves and other equipment, causing higher maintenance and equipment repair and replacement costs. In addition, the presence of hydrocarbon liquids also increases the risk of hydrate formation, which can result in reduced flow or equipment damage. By accurately measuring HCDP and achieving the proper temperature-pressure levels for the flowing gas, natural gas companies are able to reduce costs and ensure product quality.
Determining the Hydrocarbon Dew Point
Traditionally, the most common method of determining the hydrocarbon dew point online was to use a chilled-mirror device that reduces the temperature of a mirror in a measurement chamber filled with the natural gas. Other dedicated HCDP analyzers using different measurement techniques are also available. However, all of these tools provide an HCDP only at a single pressure and are dedicated analyzers that only provide a single measurement.
A significant alternative to these single measurement devices is for the natural gas company to use a gas chromatograph to calculate theoretical HCDP for measurement and reporting. While at first glance, using such a sophisticated device might seem like a costly alternative, in fact using a GC to measure HCDP saves time and money for the natural gas company.
By measuring and reporting HCDP using the same GC analyzer used for other custody transfer measurements, natural gas companies can reduce the number of analyzers and associated equipment required, and thus cost. The theoretical HCDP at multiple pressures and the cricondentherm (the maximum HCDP at any pressure) can be calculated and reported using the composition determined by a gas chromatograph and industry-accepted equations of state.
When a company uses a GC it already has installed, there is no additional footprint required, no installation costs,
no new design requirements and no additional training needed for new equipment, all adding up to significant
Using a Gas Chromatograph to Calculate HCDP
A C6+ gas chromatograph, which is typically used for the natural gas custody transfer, calculates the heavier components in the gas (hexanes, heptanes and octanes) using a fixed ratio, which is not appropriate for the measurement of the hydrocarbon dew point and can result in large errors. Therefore, to calculate hydrocarbon dew point accurately, the typical natural gas GC must have the ability to perform a C9+ analysis to quantify the heavier components in the gas.
This extended application is included in some GCs and may be an option in others. When evaluating a GC for
hydrocarbon dew point measurement, it’s important to specify one that
has HCDP calculation capabilities built-in including:
• The ability to read line pressures from the analog inputs or through a Modbus communication link.
• Expanded calculation and alarming capabilities.
• Trending capabilities.
The principal purpose for HCDP measurement is to calculate the cricondentherm or HCDP at a fixed pressure for reporting and gas quality monitoring. However, the gas chromatograph’s ability to calculate the HCDP at up to four different pressures provides companies with further practical benefits. HCDP measurement can provide an early warning system for two-phase flow, a condition that can cause problems in the pipeline flow. It can also verify that the sample handling system is operating properly and help optimize heater performance.
Two-phase Flow Alert
Measuring hydrocarbon dew point can provide an important early warning before there is two-phase flow in the pipeline, a situation that will cause significant flow measurement errors. In normal single-phase gas flow conditions, the HCDP of the gas is less than the flowing temperature and all of the hydrocarbons are in the gas phase.
If the gas becomes richer and the HCDP of the mixture increases above the pipeline temperature, the heavy hydrocarbons will drop out into the liquid phase and the remaining gas will have an HCDP equal to the flowing temperature. If there is two-phase flow (gas and liquid), all high accuracy flow measurement technologies will produce significant errors.
A hydrocarbon dew point within 10 degrees Fahrenheit of the flowing pipeline temperature indicates the immediate risk of a two-phase flow condition occurring. Calculating the HCDP at the flowing pressure and comparing it to the flowing temperature can provide an alert before there is two-phase flow, providing an early warning, so that pipeline operators can take action to mitigate the situation (see Figure 3).
Sample System Performance
The same principle can be used with the sample handing system. If the sample HCDP begins to track the ambient temperature, it can indicate that the heavy (and high energy content) components are dropping out and the sample is no longer representative of what is flowing in the pipeline. An alert can be created so operators can address it before it results in flow measurement errors.
Measuring hydrocarbon dew point
is a standard and critical step for the bottom line for natural gas companies as it allows them to meet tariff assessment and contract requirements. By using a GC for HCDP measurement, however, pipeline operators can reduce the number of analyzers and associated equipment required, and thus can achieve a range of additional cost savings, including reduced maintenance, lowered equipment costs, and improved efficiency.
Bonnie Crossland is a Rosemount Gas Chromatographs product manager for Emerson Process Management. She has several years of experience as a product marketing manager in the oil & gas industries, having worked with companies such as GE Energy, Baker Hughes, and Nalco Champion. Crossland is a member of ISA and received her bachelor’s in Engineering from Rutgers and her MBA from the University of South Carolina.Tags: Hydrocarbon Dew Point (HCDP), September 2016 Print Issue