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Separating and Reporting Nitrogen, Carbon Dioxide, and C1­ C7+ Hydrocarbons in Demethanized Liquefied Natural Gas According to GPA 2177 Application Note 228-366

November 1996

Authors

Gerben de Jonge and Peter van der Sluijs AC Analytical Controls BV, P.O. Box 10.054, 3004 AB Rotterdam, Innsbruckweg 35, 3047 AG Rotterdam, The Netherlands

Introduction

Natural gas normally refers to the gaseous fossil-based equivalent to oil. Found in geological accumulations, the composition varies considerably, ranging from nearly pure nitrogen, carbon dioxide, or methane to a mixture of hydrocarbons and gases. The largest use of natural gas is as a fuel. Natural gas is also a chemical feedstock--a source of pure single hydrocarbon gases. Gas from a natural gas field will burn without processing, but it usually requires treatment to remove or to control the level of particular components affecting regulatory compliance or product quality. For example, the primary use of the natural gas fraction C1­C6 is as a fuel; it usually moves by pipeline. This requires the removal of a number of components, such as potential hydrocarbon liquids (C6+), to prevent condensation in the pipeline.

If no pipelines are available to distribute the gas, natural gas producers apply pressure to liquefy the gas, decrease its volume, and prepare it for batch transport. After transportation, the recipient removes the pressure and the liquefied gas converts back to a gaseous state. It is possible to remove methane from liquefied natural gas. Demethanizing natural gas results in two fractions. The first fraction contains a high concentration of methane and a low concentration of high boiling hydrocarbons. The primary use of methane is as a petrochemical feedstock for fertilizers. Conversely, the second fraction has a low concentration of methane and a high concentration of ethane, propane, and high boiling hydrocarbons. Refiners use this second fraction as fuel or as a feedstock for the cracker. This application note describes the analysis of demethanized liquefied natural gas streams according to GPA standard 2177.

Abstract

The Hewlett-Packard/Analytical Controls (HP/AC) Natural Gas Analyzer complies with GPA standard 2177 in determining nitrogen, carbon dioxide, and hydrocarbons from C1 through C7+ in demethanized liquefied natural gas streams. The analyzer assures repeatability of concentration levels and retention times of demethanized liquefied natural gas components. Its dedicated software controls all events within the gas chromatography system, including calibration, physical property calculations, and reporting.

ANALYTICAL CONTROLS

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Experimental

The HP/AC Natural Gas Analyzer (NGA) consists of the HP 6890 Series gas chromatograph (GC) with electronic pneumatics control (EPC), a packed column, and a thermal conductivity detector (TCD). A liquid-sampling valve introduces the sample and allows analysis of demethanized liquefied natural gas streams. Table 1 contains the specifications for the packed column performing GPA 2177 analysis on demethanized liquefied natural gas. A dedicated software package, the HP/AC Report Generator, fully integrates with the HP ChemStation in a Microsoft® Windows® environment. Together, the HP/AC Report Generator and the HP ChemStation software automate all aspects of calibration, gas analysis, and customized data reporting.

Table 1. Packed Column Specifications for the HP/AC NGA for GPA 2177 Length (ft) 30 Outer Diameter (in) 1/8 Column 35% DC 200/500 on Chromosorb PAW 80/100

Table 2. Typical Concentration Ranges of Natural Gas Components Component Nitrogen Carbon dioxide Methane Ethane Propane Isobutane n-Butane + 2,2-Dimethylpropane Isopentane n-Pentane 2,2-Dimethylbutane 2,3-Dimethylbutane + 2-Methylpentane 3-Methylpentane + Cyclopentane n-Hexane Heptanes and heavier Concentration Range (mole %) 0.01 ­ 0.01 ­ 0.01 ­ 5.0 5.0 5.0

0.01 ­ 95.0 0.01 ­ 100.0 0.01 ­ 100.0 0.01 ­ 100.0 0.01 ­ 15.0 0.01 ­ 15.0 0.01 ­ 0.01 ­ 0.01 ­ 0.01 ­ 0.5 0.5 5.0 5.0

0.10 ­ 15.0

Analysis

The HP/AC NGA system separates and quantitates hydrocarbon components and inert gases found in demethanized natural gas. The analyzer reports on the concentration levels of nitrogen and carbon dioxide present in the sample as well as individual hydrocarbons in the C1­C6 range. The C7+ fraction is reported as a group. Table 2 shows the typical concentration ranges of the components analyzed. After introduction into the HP/AC NGA system, the sample passes

into the packed column, which separates nitrogen/air, carbon dioxide, and the C1 to C6 hydrocarbons. After the elution of n-hexane, the liquid-sampling valve switches and puts the column in backflush position to quantitate the C 7+ fraction. Figure 1 illustrates the flow diagram of the HP/AC NGA system for GPA 2177. Figure 2 illustrates a chromatogram produced by the HP/AC NGA system. A complete analysis takes only 43 minutes.

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He Flow A Liquid Sample In Liquid Sample Out

OFF

Column 1

S

P C

OFF

4 3 2 1

W

PTA

Detector A TCD

Figure 1. Inert Gases and C1­C7+ Hydrocarbons in Demethanized Liquefied Natural Gas Streams

4 5 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 7 6 8 9 10 10 15 11 12 13 20 25 30 Nitrogen Methane Carbon dioxide Ethane Propane Isobutane n-Butane Isopentane n-Pentane 2,2-Dimethylbutane 2,3-Dimethylbutane and 2-Methylpentane 12. 3-Methylpentane 13. n-Hexane Heptanes + 35 40 min

Operating Conditions for the HP/AC NGA According to GPA 2177 (Late Backflush) Initial oven temperature Run time Flow (helium) Detector (TCD) Reference flow Liquid sampling valve 120 °C 43 min 20.0 mL/min 200 °C 30.0 mL/min 0.2 µL

3 2 1 0 5

Figure 2. Results of a Demethanized Liquefied Natural Gas Analysis According to GPA Standard 2177

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Performance Assurance

The methodology and equipment of the HP/AC NGA system are thoroughly tested to ensure compliance with GPA 2177. The stability of the HP 6890 Series GC's EPC contributes to excellent precision. The repeatability of the results is mainly dependent on sample handling and injection. For proper sample handling and injection, it is advisable to use a floating-point piston cylinder to pressurize the sample and to transfer it to the liquid-sampling valve. The HP/AC NGA system assures repeatability of concentration levels and retention times. Tables 3 and 4 contain the assured concentration range and retention time repeatability specifications for liquefied natural gas streams.

Table 3. Assured Concentration Range Repeatability for the HP/AC NGA for GPA 2177 Component Concentration Range (mole %) 0.975 1.497 0.494 53.569 27.647 2.980 6.101 0.985 1.960 0.025 0.690 0.235 1.303 0.513 HP/AC Assured Repeatability Relative Standard Deviation (%) 4.0 4.0 4.0 1.0 0.5 2.0 2.0 4.0 4.0 15.0 6.0 6.0 6.0 10.0

Nitrogen Carbon dioxide Methane Ethane Propane Isobutane n-Butane Isopentane n-Pentane 2,2-Dimethylbutane 2,3-Dimethylbutane + 2-Methylpentane 3-Methylpentane n-Hexane Heptanes+

Table 4. Assured Retention Time Repeatability for the HP/AC NGA for GPA 2177 Component Retention Time (min) 2.473 2.749 3.153 3.565 4.841 6.334 7.370 10.550 11.831 14.640 16.981 18.495 19.820 33.800 HP/AC Assured Repeatability Relative Standard Deviation (%) 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.1

Nitrogen Carbon dioxide Methane Ethane Propane Isobutane n-Butane Isopentane n-Pentane 2,2-Dimethylbutane 2,3-Dimethylbutane + 2-Methylpentane 3-Methylpentane n-Hexane Heptanes+

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Calculations

The amount of thermal energy in natural gas determines its value. Other physical properties also contribute to value determination. Computing physical properties of the sample stream is a necessary step in evaluating gas composition data. The HP/AC NGA system eliminates many time-consuming and error-prone manual calculations by automating them for the analyst. Some of these include calculations established in ASTM methods D 2421, D 2598, D 3588, ISO method 6976, and GPA standard 2172. Table 5 lists the standard calculations performed by the HP/AC NGA system. To reduce operator involvement, the software contains standard databases of component constants and formulas. The system uses these databases to calculate physical properties. A user-friendly edit mode allows authorized users to edit the databases. Figure 3 illustrates the formula editor. Users may add calculations, customized to their needs, in a field within the HP/AC Report Generator editor. The HP/AC NGA software includes several standard report formats and enables users to create customized reports easily.

Table 5. Standard Gas Calculations Available* Natural Gas · Liquid volume · Liquid vapor pressure · Relative density of liquefied petroleum gas (LPG) · Compressibility of mixture · Real specific gravity at 15.55 °C (60 °F) · Real Btu · GPM · Ideal calorific value on molar basis (inferior + superior) · Ideal calorific value on mass basis (inferior + superior) · Ideal calorific value on volume basis (inferior + superior) · Real calorific value on volume basis (inferior + superior) · Ideal wobbe index (superior) · Real wobbe index (superior) · Density * Users can add their own calculations.

Figure 3. The Formula Editor. Authorized users can easily change standard formulas and add customized formulas to calculate physical properties.

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Conclusion

Knowledge of the composition of natural gas is essential for establishing market value, quality control, and regulatory compliance. The HP/AC NGA for GPA 2177 analyzes demethanized liquefied natural gas streams to determine the concentration levels of C1 through C7+ hydrocarbons, inert gases, and toxic gases. The HP/AC NGA not only complies with GPA 2177, it assures performance in terms of concentration and retention time repeatability. The analyzer's dedicated software automates the analysis, calibration, and reporting of the individual component concentrations and the computation of physical properties of the sample stream. This can reduce errors and increase laboratory productivity.

For More Information

For more information on HP/AC natural gas analyzers, please see the following publications. 1. G. de Jonge and P. van der Sluijs, "Separating and Reporting Inert Gases and C1­C14+ Hydrocarbons in Demethanized Liquefied Natural Gas according to GPA 2186," HP Publication 5965-5810E, November 1996. 2. G. de Jonge and P. van der Sluijs, "Separating and Reporting Inert Gases and C1­C6+ Hydrocarbons in Demethanized Liquefied Natural Gas According to GPA 2261," HP Publication 5965-5813E, November 1996. 3. G. de Jonge and B. Frederick, "Separating and Reporting Hydrogen Sulfide, Inert Gases and C1­C6+ Hydrocarbons in Natural Gas According to GPA 2261 Extended," HP Publication 5964-9524E, March 1996. 4. G. de Jonge and B. Frederick, "Separating and Reporting Hydrogen Sulfide, Inert Gases and C1­C14+ Hydrocarbons in Natural Gas According to GPA 2286 Extended," HP Publication 5964-9613E, March 1996. 5. G. de Jonge and B. Frederick, "Separating and Reporting Hydrogen, Helium, Inert Gases and C1-C8 Hydrocarbons in Natural Gas According to ISO 6974," HP Publication 5964-9614E, March 1996.

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Hewlett-Packard shall not be liable for errors contained herein or for incidental or consequential damages in connection with the furnishing, performance, or use of this material. Information, description, and specifications in this publication are subject to change without notice. Microsoft® is a U.S. registered trademark and Windows® is a U.S. registered trademark of Microsoft Corporation. Copyright © 1996 Hewlett-Packard Company Printed in USA 11/96 (23) 5965-5811E

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