The natural gas industry is required to maintain specific standards for gas quality and composition. These standards are in place to ensure better operational efficiencies throughout the natural gas value chain. Limits on a range of gas quality specifications help protect the integrity of pipelines to ensure reliable gas transportation. They also ensure the reliable performance of end-use equipment as gas-fired equipment is designed to operate within a particular range of gas specifications. If gases outside this range are combusted, this can lead to a range of safety, operability, and financial problems.
Roughly 70-90% of natural gas is methane, while 0-20% consists of ethane, propane and butane, and other heavier hydrocarbons.
Natural Gas Composition
While natural gas is mostly methane, there is a number of other components that can be toxic, corrosive, degrade its quality as a fuel, and be present as pollutants when burned. Consequently, business operators in the supply chain use a gas analyzer to characterize what is flowing through the network for delivery to all types of consumers. Gas analyzers evaluate the gas contents to validate they meet proper gas quality specifications.
In some cases, the analysis is basic and can be carried out by a simple analyzer designed to determine heat content by providing C6+ BTU/Calorific Value (CV) analysis. This is suitable for users who are primarily concerned with BTU value and Wobbe Index, such as gas turbine operators.
Other users must have a deeper analysis that goes into far more detail. In this article in Hydrocarbon Engineering magazine, Asad Tahir discusses ways to approach these applications where an extended analysis such as the C9+ hydrocarbon analysis, plus characterization of sulfur, both in total and by specific compounds are needed. Sulfur is the real challenge for natural gas because of what it does, but also because it can be difficult to measure.
It remains critical for those in the delivery chain to monitor the overall gas composition and sulfur content in its entirety continuously since it can vary greatly with changes in gas sources. If the pipeline switches from a conventional gas field supply to a mix from various shale sites, or from gas processed by a less effective removal facility, there can be significant fluctuations. Pipeline operators must pay particular attention to composition due to operational and equipment durability concerns. The corrosiveness of sulfur affects pipeline integrity, as well as valves and compressors.
When using traditional analysis methods, this level of detail requires several analyzers employing different technologies, each aimed at some specific portion of the composition spectrum. Other methods require elaborate air-purged enclosures that add significant capital and operating costs tied to installation, utilities, heat tracing, long sample lines, climate control and HVAC, ultimately driving up the total cost of ownership.
Rosemount 700XA Gas Chromatograph is the industry’s first explosion-proof, single-analyzer solution capable of measuring BTU, H2S, total sulfur, and hydrocarbon dew point (HCDP), streamlining natural gas quality measurements while eliminating the need for purge lines.
Streamlining Complex Natural Gas Analysis
To address the challenges of complex natural gas analysis, Emerson has introduced the industry’s first explosion-proof, single-analyzer solution that allows users to replace up to four analyzers with one by performing four measurements fully traceable to industry standards while eliminating the need for purge lines. These measurements include heat content (BTU), hydrogen sulfide (H2S), total sulfur (TS) content, and hydrocarbon dew point (HCDP)—all delivered by Emerson’s Rosemount 700XA Gas Chromatograph. The 700XA is a C9+ analyzer equipped with a micro flame photometric detector (µFPD) that provides accurate measurement values for sulfur and its compounds.
Arguably, the most complete analysis of sulfur and its compounds, outside of a laboratory environment, is available with a gas chromatographic flame photometric detector (FPD). The working principle employed is that sulfur produces a unique blue flame in the presence of burning hydrogen and air. Photons from the blue emission are then filtered and passed through a photomultiplier tube. These signals are amplified and processed in the electronic compartment or controller. Usually an FPD stage is used in combination with a GC – where the column separates the individual sulfur compound species – which are then detected, identified, and measured using the FPD.
Analytical detection techniques for hydrogen sulfide and total sulfur in flue gas, fuel gas, and natural gas.
Comparing Sulfur Analyzers
The article also compares the gas chromatographic flame photometric detection of hydrogen sulfide and total sulfur in flue gas, fuel gas, and natural gas to other analytical detection techniques. These technologies include tunable diode lasers (TDL) and lead acetate paper analyzers. Check out the article for more on the measurement ranges of these technologies and the limit of detection.
For more on the technologies and solutions designed for gas quality and content evaluation, visit the Gas Analysis pages at Emerson.com. You can also connect and interact with other engineers in the Oil & Gas and Chemical Groups at the Emerson Exchange 365 community.
