Hi everyone. This is Shane Hale, natural gas product marketing manager. I recently wrote an article for Pipeline & Gas Journal about using gas chromatographs to determine hydrocarbon dew point. The determination of hydrocarbon dew point (HCDP), the temperature at a defined pressure at which hydrocarbon liquids begin to form, has become critical for the natural gas industry. A big reason is that producers are focusing on extracting heavier gases in traditional and shale plays in an effort to produce more profitable natural gas liquids (NGLs) rather than the natural gas that is selling at historical lows. This has increased the risk of hydrocarbon liquids entering or forming in gas transmission networks if this rich gas is not processed fully.

The traditional method of determining the hydrocarbon dew point online is to use a chilled-mirror device that reduces the temperature of a mirror in a measurement chamber filled with the natural gas until enough hydrocarbon mist condenses on the mirror to be detected. Other dedicated HCDP analyzers using different measurement techniques are also available; however, they all provide a HCDP only at a single pressure and are dedicated analyzers that provide a single measurement.

An alternative to a dedicated HCDP analyzer is using an equation of state (EOS) to calculate the hydrocarbon dew point at any pressure from the composition obtained from a gas chromatograph (GC). By entering the composition of the natural gas into a recognized equation of state, the theoretical HCDP can be calculated for any pressure as well as the cricondentherm (the highest dew point temperature at any pressure). The validity of the calculated value depends on the accuracy of the composition used especially for the higher carbon number hydrocarbons (C6 to C9).

Gas chromatographs are already used in custody transfer measurement to determine the energy content, compressibility, density, and other physical properties. Therefore, using a gas chromatograph to determine the HCDP using an EOS provides additional valuable information from already required equipment.

To learn how the C9+ gas chromatograph can be used to calculate hydrocarbon dew point at any pressure allowing pipeline operators to take corrective action before heavy hydrocarbons enter the network, click HERE. And let us know if you’re using, or have considered using a gas chromatograph at your plant!

Hi, my name is Shane Hale, Product Marketing Manager for Natural Gas at Rosemount Analytical, and today I’d like to discuss a gas chromatograph application for the amine systems in natural gas processing that you may not be familiar with, but can dramatically reduce foaming events and increase production rates.

In natural gas processing, amine systems are frequently used to remove CO₂ and H₂S from rich gas streams. When hydrocarbon liquids are introduced into the amine contactor, however, foaming can occur which significantly reduces the efficiency of the acid gas extraction.  This happens because, when hydrocarbon liquids enter the contactor, they are highly soluble into the amine solution and reduce the surface tension of the aqueous solution. The reduced surface tension then aids in creating bubbles of gas in the amine solution, resulting in foaming. At that point, operators need to reduce flow and may even have to inject foaming inhibitors into the system to regain control.

Avoiding foaming is difficult. The efficiency of amine systems to remove H₂S generally increases with lower operating temperatures, and the efficiency at removing carbon dioxide occurs at a specific temperature. However, lower temperatures in the contactor also increase the potential for liquid hydrocarbons to form in the inlet stream and thus increase the potential for foaming to occur.

C9+ Gas Chromatography

Figure 1 – Calculating the Hydrocarbon Dew Point of the inlet stream at the contactor pressure provides an early warning for liquid hydrocarbons in the inlet stream and defines a minimum temperature for the lean amine inlet stream to avoid amine foaming from liquid hydrocarbons.

The solution to the problem is hydrocarbon dewpoint (HCDP) and this is where gas chromatography comes into play. Determining the HCDP of the inlet gas provides the opportunity to (1) avoid hydrocarbon liquids entering the contactor and (2) control the amine temperature to a set-point that optimizes the efficiency of the acid gas extraction while also avoiding the risk of liquid hydrocarbons forming in the contactor. The theoretical HCDP of a gas mixture can be calculated from the gas composition using an equation of state. Typical gas chromatographs used in natural gas applications measure individual hydrocarbons up to n-pentane, and combine all the heavier components as a C6+ value. However, the components that drop out as liquids and cause the foaming issues are the components heavier than C6, so calculating the HCDP with a C6+ analysis (using assumed ratios of C6/C7/C8) will provide inaccurate results that will not be suitable for use in a control strategy. A C9+ gas chromatograph measures the ratio of C6, C7 and C8 components (with heavier components reported as C9+) and provides a much more accurate HCDP calculation that can then be used to optimize the control strategy.

Figure 2 – The process pressure is used to calculate the HCDP at process conditions that provides a two-phase flow early warning for use in the control strategy to avoid foaming in the contactor.

Determining the Phase of the Inlet Gas
When the inlet gas temperature is below the HCDP, the flowing stream is a single phase vapor. As the gas becomes richer with heavy hydrocarbons, the calculated HCDP will approach the stream temperature. When the HCDP reaches the stream temperature, the heavier components will begin to drop out into the liquid phase, increasing the risk of foaming in the amine contactor. By calculating the HCDP at the line pressure with the C9+ gas chromatograph, the difference between the stream temperature and the HCDP can be monitored. As the HCDP approaches the stream temperature an alert can be triggered that enables the operator, or the control strategy, to take actions to reduce the HCDP before liquids form and enter the amine contactor.

Using HCDP for Amine Inlet Temperature Control
The temperature of the amine contactor is typically controlled by cooling the lean amine prior to entry into the contactor to maximize the efficiency of the acid gas removal. However, if the temperature of the contactor is below the HCDP of the inlet gas at the contactor pressure, then liquid hydrocarbons will begin to form as the inlet gas enters the contactor and the risk of amine foaming greatly increases.

As the HCDP varies with pressure, the HCDP of the inlet gas will change as it enters the contactor. By calculating the HCDP of the inlet gas at the pressure of the amine contactor, the minimum temperature of the inlet amine can be determined and used in the control strategy to minimize the risk of amine foaming.

If the determined minimum temperature is too high for the efficient acid gas removal, actions can be taken to reduce the HCDP of the inlet gas while also avoiding the risk of amine foaming.

Emerson has led the industry in the development of gas chromatography for C9+ applications and customized solutions using the 700XA Gas Chromatograph by Rosemount Analytical.

Are you struggling with Amine Foaming in your plant? If so, we’d like to hear from you…

Click on the following links to find additional resources for this blog:

• Avoiding Amine Foaming Application Note
• Hydrocarbon Dew Point (HCDP) Application Note

Hi everyone. This is Michael Gaura, product marketing manager with the Gas Group. I recently wrote an article for Waste Age Magazine about extracting valuable gas from landfills and people seem interested in the topic. I thought I’d share some of this data with you here.

To utilize landfill gas (LFG) in plant operations such as fueling boilers, power generators and turbines, or to sell it to a natural gas network, the landfill operator must understand the components present in the gas stream as well as their concentrations. A gas chromatograph makes this analysis possible. A typical gas chromatograph used in landfill operations is shown in Fig 1.

Figure 1

Methane and carbon dioxide (CO₂) are often the two components with the highest concentration levels found in LFG applications. Oxygen, nitrogen and water are typically found also at percent levels. Other components, such as ammonia, silanes and hydrogen sulfide (H₂S) also may be present at concentrations of several hundred ppm.

Knowing the concentrations of each of the typical components determines the appropriate method of gas treatment, blending or usage. The concentrations also may be required as part of permitting, as defined by a local air quality board or environmental agency.

Some general guidelines for landfill gas usage include:

• Landfill gases with high-energy content and low impurities may be sold into a natural gas network.
• Equipment fueled by LFG meeting a defined range of energy values (CV or BTU) will ensure efficient and reliable operation. Excursions outside of these defined ranges will result in equipment damage or reduced performance.
• If the non-methane components of the LFG are too high, it may be too “lean” for proper engine performance, requiring the addition of natural gas or another fuel source.
• If the H₂S content is higher than the equipment rating, pipeline specification or regulatory agency-permissible level, it will need to be removed. The only way to safely determine the continuous H₂S level is to use an on-line analyzer, as manual testing may miss variances or present unsafe concentrations for human exposure.
• Common H₂S removal methods include water washing, amine absorption, pressure swing adsorption (PSA) or turbo expander usage. Regardless of the system used, monitoring both the inlet “sour” gas and the outlet “sweet” gas is required to ensure efficient operation of the H₂S removal process. A sudden change, or even a gradual increase, of the H₂S concentration in the sweet gas, indicates that the removal system requires inspection or maintenance. A process gas chromatograph that monitors the H₂S concentration at the H₂S removal outlet can identify off-specification gas early, preventing contamination of an entire batch.
• High oxygen (O₂) levels can indicate that a serious operational safety risk is present or may indicate an issue with the landfill’s degradation process.

To read the entire article, please click HERE.

Does your plant have the potential to reuse any of these valuable gases? If you have any questions, let me know.

I am Carolyn Snyder, business development manager for the process industry at Rosemount Analytical.

For many years, all process gas chromatographs were installed in shelters that usually cost significantly more than the analyzers themselves. From a technician’s point of view, a shelter was desirable for its climate control and comfort to troubleshoot and repair the analyzer. However, using a fully enclosed shelter requires several compromises. First, you give up proximity to the point of measurement, which means you spend more on cabling and sample tubing (often heated). Second, a shelter is limited in the number of units it can house. As your needs change, you may be required to invest in additional expensive shelters to accommodate the changes in your analytical scope. Because of these issues, most major suppliers of GCs have produced some form of a field-packaged unit that is theoretically capable of existing in a non-climate-controlled environment.

Which is why I was quite surprised to hear many of these suppliers still strongly advocate the use of conventional analyzers at the recent IFPAC conference held in Baltimore, Maryland. Sitting through several papers, I listened to presenters explain that only the simplest measurements can be made with field-mounted units. They also discussed some service-related issues centering on the expense of the modular concept, where the entire module is replaced rather than repaired in the field, which can be very costly.

What I’ve discovered over the past few months is that none of these issues apply to the field-mounted gas chromatographs manufactured by Emerson (sold as Rosemount Analytical into the process industry and Daniel Danalyzer into the natural gas industry).

First, the Emerson GCs all go through an environmental chamber to ensure there is no failure when temperatures vary from 0° to 130°F. They are designed with access to the various parts – electronics, boards, columns, detectors, etc. – so that repair in the field is feasible. Most importantly, these field-packaged analyzers are not restricted to simple applications. Some of the most strenuous measurements are easily performed by these units which house multiple valves, columns and detectors in addition to stream switching capability. The measurement of C9+ with HHV (higher heating value, or BTU) and HCDP (hydrocarbon dewpoint) has been provided in scores of field analyzer units to the satisfaction of many major hydrocarbon processing companies.

In short, performance does not have to be sacrificed in a field housing analyzer if it is properly designed and implemented.

Hi, I’m Michael Gaura, Product Marketing Manager at Emerson Rosemount, and I’m the Analytic Expert this week.

As you know, gas chromatography is one of the most widely used techniques for analyzing hydrocarbon mixtures. Chances are you have a lot of these systems in your lab, in permanently installed online systems and in the field with portable systems. Because they’re so widely used, anything that makes gas chromatographs less costly and easier to use is good news for a lot of users in the oil and gas industries. Actually, in chemical, refining and hydrocarbon processing industries too, since GCs are employed there as well. So, I’m happy to say I have very good news.

This month, Emerson has introduced a new gas chromatograph called the 700XA. We don’t generally use this blog to tell you about products, but the 700XA represents an advance in technology, so you may want to be aware of it. First of all, the 700XA operates to specification across the widest range of temperatures in the industry – from -40 to 60^o C (-40 to 140^o F). This means the GC doesn’t require an expensive, environmentally controlled shelter to house it. If the 700XA happens to be in an existing shelter and the shelter’s environmental system fails, the GC will keep on ticking. In other blog posts and our newsletter, we’ve written about how much money operating without a shelter can save you. It’s tens of thousands of dollars. Check that out here.

The new 700XA also operates with the highest C6+ and C9+ repeatabilities in the industry in both controlled and uncontrolled environments. These repeatabilities improve the value of the energy content measurements of natural gas streams, leading to more accurate billing and process control. This is a boon for any user.

The new GC features a simplified design. Why should you care? Fewer overall parts mean less maintenance. Valves are constructed with a single bolt for fast troubleshooting, and electronic boards simply snap into place. Most service calls for standard maintenance take less than an hour. The annual average cost of service for the 700XA over five years is expected to be less than $300! Count the money you’ll save.

If you use Emerson GCs, you know how simple and high-performance the software is. The 700XA employs MON 20/20 workstation software, offering access to automatically saved chromatograms, simple-to-integrate user calculations and all of the information you require to monitor and maintain your gas chromatograph. The GC includes multiple Ethernet connections as a standard and communicates via Modbus, traditional IOs, and FOUNDATION Fieldbus.

You probably know that Emerson has been building GCs for over 50 years, so it’s really our technology to advance. The 700XA represents that kind of step forward.  It’s worth taking a look at.