Coal, Gas

Gas Quality: Gas Turbine Boom Places Premium on Ensuring High-Quality Fuel Gas

Issue 10 and Volume 105.

By S. Zaheer Akhtar, P.E., Bechtel Power Corp.

Natural gas is currently the most widely used fuel for new power plants, mainly due to attractive gas pricing, low emissions and the favorable capital costs of gas turbine power plants. To meet the elevated demand for natural gas, the fuel supply infrastructure – including pipelines, storage facilities and metering stations – is being expanded. As this expansion takes place, it will be important to diligently monitor gas quality to prevent downstream damage to the turbine.

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To maintain and set the minimum safety standards and quality for natural gas, the Gas Safety (Gas Quality) Regulations of 1999 were enacted under the Gas Safety Act of 1997. The pipeline gas available in the U.S is governed by these regulations (Table 1) and hence the term “pipeline-quality gas.”

Gas transmission companies recognize the merits of maintaining high quality gas in their transmission systems and the need to minimize the water content in the gas pipeline. Reducing the moisture content of gas prevents: 1) corrosion in the pipeline, 2) freeze-up due to hydrate formation, 3) condensation requiring frequent blowdown, and 4) reduced line capacity due to water accumulation. As shown in Table 1, the water content in U.S. pipelines is limited to 112 mg per cubic meter (equivalent to approximately 7 lb of water per million scf of gas). Typical moisture levels in the U.S gas pipelines are in the range of 4-7 lb of water per million scf of gas. These low levels of water content are achieved by scrubbing with ethylene glycol. However, a process upset at the chemical treatment facility could result in carryover of the scrubbing liquid in the gas supply. Also, a spillover of the chemical inhibitors from the chemical process can raise the hydrocarbon dew point. It is therefore essential that the specific properties of the gas being used, such as the moisture dew point, hydrocarbon dew point and the gas hydrate formation point, are known and well defined.

Most of the solids in a pipeline are generated from the slow oxidation and corrosion of the pipeline itself, typically appearing in the form of fine iron oxide particles. To remove these particulates, the fuel gas requires conditioning before being utilized in the gas turbine. Conditioning equipment is typically limited to media filtration, inertial separator drums and coalesing filters to remove particulates and liquids. Electric start-up heaters are often provided to supply the required superheat in the gas, and many of today’s advanced gas turbines also utilize a main fuel gas heater that extracts heat from the feedwater used in the HRSG (heat recovery steam generator). The main fuel gas heater is used primarily for gas turbine performance enhancement, but also provides the gas superheat when the plant is in normal operation.

Moisture Dew Point

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To determine the adequacy of gas superheat, the moisture dew point, the hydrate formation point and the hydrocarbon dew point should be known. The moisture dew point of the gas can be determined if the water content in the fuel gas is known. Pipeline gas can typically carry up to 7 lb of moisture per million scf of gas as per the Gas Safety (Gas Quality) Regulations of 1999. Based on published charts (Figure 1), natural gas with moisture content of 7 lb per million scf has a moisture dew point of 20 F at 500 psia. If the moisture content is decreased to 4 lb per million scf, the moisture dew point decreases to around 8 F at the same pressure. Figure 1 can be used for lean, sweet natural gas to determine the moisture dew point based on water content of the gas, pressure and composition.

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For “sour” natural gas containing more than 5 percent CO2 and/or H2S, a correction should be applied to the moisture content before using Figure 1. This correction increases the water carrying capacity of the fuel gas, resulting in a higher dew point. Separate charts (Figure 2 and Figure 3) are available to determine the higher water content correction due to the presence of acid gas components (CO2 and H2S) in the fuel gas.

Gas Hydrates

Gas metering station.
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Gaseous hydrocarbons form hydrates at temperatures considerably above the freezing point of liquid water. At the moisture dew point, the water in the natural gas starts to condense. Under certain conditions of temperature and pressure, the condensed water forms gas hydrates. Hydrates are formed by the linkage of hydrocarbon molecules and water molecules. The structure of the gas hydrates is crystalline in nature and forms ice-like particles that drop out in the system and lead to partial or complete plugging of gas lines, valves, equipment and instruments.

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The formation of gas hydrates is favored under high pressure and low temperature conditions. The hydrate formation line shown in Figure 1 gives the approximate conditions when hydrate formation can be expected in lean, sweet natural gas. When H2S is present in natural gas mixtures, the hydrate formation temperature is substantially higher at a given pressure. On the other hand, CO2 has a much smaller impact and often reduces the hydrate formation temperature at a fixed pressure. Hydrocarbon molecules larger than n-C4H10 do not form hydrates as they are too large to stabilize the lattice structure. For an accurate determination of the hydrate formation point, rigorous methods utilizing the vapor-solid equilibrium constants should be used [Ref. 8].

Hydrocarbon Dew Point

The hydrocarbon dew point of the fuel gas can be determined by using equilibrium flash calculations. These calculations are iterative and therefore tedious in nature if done manually. An easier method is to use commercially available software to perform the process calculations quickly and with greater accuracy. This type of software can also be used to calculate the moisture dew point if the moisture content of the gas is known.

Joule-Thomson Effect

The iso-enthalpic expansion of natural gas – such as that experienced across a pressure reducing valve, which results in cooling of the gas – is called the Joule-Thomson effect. The Joule-Thomson effect has been used successfully in the cryogenic industry for achieving low gas temperatures for liquefaction of gases.

In the fuel gas system for the gas turbine, the Joule-Thomson effect is observed when gas pressure in the supply pipeline is let down across a pressure control valve for use in the plant’s fuel gas system. It is estimated that the natural gas cools by about 7 F for every 100-psi drop in pressure. If the pressure drop is significant, the cooling of the gas could lower the gas temperature to the moisture dew point or the hydrocarbon dew point. When the moisture dew point is reached, it is likely that gas hydrates will be formed in the pipe and the pressure control valve.

Contaminant Removal

The contaminants found in natural gas depend on the source of gas, the chemical processing methods used for treating the gas, and the gas compression used for transmission in the pipeline. The gas supply can contain particulates, trace metals, liquids and/or sulfur.

The particulates cause fouling and erosion of the hot gas path components, erosion and plugging of combustion fuel gas nozzles, and erosion of the gas control valves. The particulates can include material such as corrosion products, sand, iron sulfide and gas hydrates. The gas hydrates can appear as particulate contaminants in the gas by dislodging and breaking up in to small pieces. Media filtration or inertial separation is generally used for removing these contaminants from the gas supply to the combustion turbine.

Among the trace metals, sodium and potassium are the only trace metals found in natural gas. These trace metals can form corrosive deposits on hot gas path components. Again, media filtration and inertial separation can be used to clean up the gas.

Liquid in fuel gas damages fuel supply and turbine hardware due to flame re-ignition and flashback. When liquid is carried over past the combustion system, the hot gas path components can be damaged. Liquid removal can be achieved by means of coalesing filters, inertial separators and gas heaters.

Sulfur in fuels causes corrosion in the turbine hot gas path components, acid corrosion at the back end of the HRSG, deposition of corrosive compounds in combination with ammonia injection used in the SCR (selective catalytic reduction), high sulfur oxides in flue gas, and solid sulfur deposition in the pipeline. Sulfur also increases the moisture dew point of the gas, increasing the likelihood of gas hydrate formation. Sulfur is removed by scrubbing the gas with an aqueous amine solution.

Fuel Gas Superheat

To prevent liquids from entering into the gas turbine combustion system, gas turbine vendors specify a minimum degree of superheat in the fuel gas (usually 50 F above the moisture dew point or the hydrocarbon dew point, whichever is greater). To ensure adequate superheat, gas heaters are provided. The main fuel gas heater (performance heater) utilizes hot feedwater from the HRSG. However, the hot feedwater is not available during plant startup and for this period an electric start-up heater is provided.

The electric fuel gas heater and the performance heater can provide the necessary superheat at the gas turbine combustion module. However, when gas hydrate formation is a problem, additional gas heaters may be required to heat the pipeline gas and ensure that hydrate formation does not occur in the gas supply pipe or in the pressure letdown valve supplying gas to the plant’s fuel gas piping system.

If gas compressors are being used to boost the fuel gas pressure to meet the requirements of the gas turbine’s combustion system, then the heat of compression can supply the required superheat specified at the gas turbine combustion module. The problem here is that most of the plants equipped with gas compressors receive gas within a wide range of supply pressures. When the gas pressure is high, it is likely that the gas compressor will not be operated. In this case the heat of compression is not available for supplying superheat to the fuel gas. Therefore, gas heaters may be required even for plants equipped with gas compressors.

Dew Point Instrumentation

Several types of high accuracy moisture dew point analyzers are available in the market with a moisture dew point range of -100 F to +60 F. Dew point can be measured automatically or manually. Manual instruments are more economical, costing less than $5,000. An example of a manual dew point instrument is the Bureau of Mines Dew Point Tester, which operates on the chilled mirror principle. It consists of a pressure chamber with a polished mirror and a viewing window. The mirror is gradually cooled by a supply of refrigerant such as propane or carbon dioxide and the operator determines the dew point based on condensation on the mirror. This instrument can be used for moisture dew point as well as hydrocarbon dew point.

Automatic instruments provide a digital readout of the dew point without operator intervention, but are more expensive. In cases where the gas is near its dew point, however, an automatic instrument would be recommended.

Analyzers are also available for specific measurement of hydrocarbon dew point in natural gas. One such automatic analyzer has an output range of -40 F to +104 F and works on the chilled mirror principle described above. All monitoring and measurement of dew point is done automatically under control of an onboard computer, rather than by an operator. It can provide an accurate hydrocarbon dew point temperature measurement regardless of whether the water dew point occurs at a higher or lower temperature than the hydrocarbon dew point. The analyzer can be located locally at a plant or at a remote location as it is designed for unattended operation. It requires only electrical power and a supply of dry purge gas.

Another type of hydrocarbon dew point detector is built-in with the gas chromatograph. The chromatograph is loaded with application software for dew point calculations. The results can be printed automatically or by operator action.


  1. “Gas Engineer’s Handbook,” First Edition, Chapter 8, pages 4/72 to 4/85.
  2. Perry, “Chemical Engineering Handbook,” 7th Edition, pages 13-17.
  3. Smith, J.M and Van Ness, H.C “Chemical Engineering Thermodynamics,” 2nd Edition, Chapter 12.
  4. “Engineering Data Book,” Gas Processors Suppliers Association, Revised 10th Edition, Volume 2, Section 20.
  5. Ametek Process Instruments, Bulletin Model 241 CE, Dew Point Monitor.
  6. Chandler Engineering, Bulletin on Dew Point Testers.
  7. Daniel Measurement and Control, Inc., Information on Model 590GC with Hydrocarbon Dew Point.
  8. Katz, D.L., “Predictions of Conditions for Hydrate Formation in Natural Gases,” Trans. AIME, Vol. 160, 1945.


S. Zaheer Akhtar, P.E., is a Senior Technical Specialist with Bechtel Power Corp. He has more than 25 years’ experience in power generation and process plants, including positions with SCECO’s Ghazlan Power Plant in Saudi Arabia, Exxon Chemical Co., General Physics Corp. and BE&K Inc. Akhtar received a bachelor’s degree in chemical engineering from the University of Engineering and Technology in Pakistan and a master’s degree in chemical engineering from the University of Manchester Institute of Science and Technology in the U.K.