Natural-gas Processing - Contaminants in Raw Natural Gas

Contaminants in Raw Natural Gas

Raw natural gas typically consists primarily of methane (CH₄), the shortest and lightest hydrocarbon molecule. It also contains varying amounts of:

• Heavier gaseous hydrocarbons: ethane (C₂H₆), propane (C₃H₈), normal butane (n-C₄H₁₀), isobutane (i-C₄H₁₀), pentanes and even higher molecular weight hydrocarbons. When processed and purified into finished by-products, all of these are collectively referred to as NGL (Natural Gas Liquids).
• Acid gases: carbon dioxide (CO₂), hydrogen sulfide (H₂S) and mercaptans such as methanethiol (CH₃SH) and ethanethiol (C₂H₅SH).
• Other gases: nitrogen (N₂) and helium (He).
• Water: water vapor and liquid water. Also dissolved salts and dissolved gases (acids).
• Liquid hydrocarbons: perhaps some natural gas condensate (also referred to as casinghead gasoline or natural gasoline) and/or crude oil.
• Mercury: very small amounts of mercury primarily in elemental form, but chlorides and other species are possibly present.
• Radioactive gas: Naturally occurring radioactive material (NORM), including radon, can accumulate in specific locations within processing equipment. This can render piping and equipment radioactive over time.

The raw natural gas must be purified to meet the quality standards specified by the major pipeline transmission and distribution companies. Those quality standards vary from pipeline to pipeline and are usually a function of a pipeline system's design and the markets that it serves. In general, the standards specify that the natural gas:

• Be within a specific range of heating value (caloric value). For example, in the United States, it should be about 1035 ± 5% BTU per cubic foot of gas at 1 atmosphere and 60 degrees Fahrenheit (41 MJ ± 5% per cubic metre of gas at 1 atmosphere and 15.6 degrees Celsius).
• Be delivered at or above a specified hydrocarbon dew point temperature (below which some of the hydrocarbons in the gas might condense at pipeline pressure forming liquid slugs that could damage the pipeline).
• Dew-point adjustment serves the reduction of the concentration of water and heavy hydrocarbons in natural gas to such an extent that no condensation occurs during the ensuing transport in the pipelines
• Be free of particulate solids and liquid water to prevent erosion, corrosion or other damage to the pipeline.
• Be dehydrated of water vapor sufficiently to prevent the formation of methane hydrates within the gas processing plant or subsequently within the sales gas transmission pipeline. A typical water content specification in the U.S. is that gas must contain no more than seven pounds of water per million cubic feet (MMCFD) of gas.
• Contain no more than trace amounts of components such as hydrogen sulfide, carbon dioxide, mercaptans, and nitrogen. The most common specification for hydrogen sulfide content is 0.25 grain H₂S per 100 cubic feet of gas, or approximately 4 ppm. Specifications for CO₂ typically limit the content to no more than two or three percent.
• Maintain mercury at less than detectable limits (approximately 0.001 ppb by volume) primarily to avoid damaging equipment in the gas processing plant or the pipeline transmission system from mercury amalgamation and embrittlement of aluminum and other metals.