New growth in shale gas production has changed the nation's energy point of view in recent years while creating new challenges in processing and transportation due to differences in specific gravities, Wobbe Index, and higher heating values. New fluid properties are affecting the design and operation of pipeline systems and compressor stations; therefore, a good quantification of their effect on the operating conditions of typical pipeline systems and compression equipment is needed.
Many compressor stations are reversing flow direction and operating with a different gas composition than what the station was originally designed to process. Using a pipeline simulation method, this paper will review the effects on the efficiency and performance of compressors when exposed to varying natural gas compositions as well as the effect on the pipeline losses. This paper will also include the case study results of a pipeline system and its associated compressor stations.
In recent years there have been significant increases in natural gas production from shale deposits throughout the United States. In an effort to reduce the cost of compressing, processing and transporting this shale gas, many compressor stations in proximity to these deposits are reversing flow direction and operating under new conditions. Principally, these compressors are operating with a different gas composition than that which the stations were originally designed to process.
With the expansion of extraction from shale formations, primarily throughout the United States, natural gas found at the numerous locations vary in composition. There are currently shale gas reservoirs spanning the north and south regions of the United States including New York, Pennsylvania, Wyoming, Colorado, Illinois, Texas, Oklahoma, and New Mexico. Individual components, such as nitrogen, methane and hydrocarbons, within these gas compositions can differ by over 10% mol subject to location. Furthermore, the component quantities in different wells at the same location can vary by similar magnitudes. The nitrogen content of the Barnett Shale formation in north-central Texas, for example, has been recorded to vary as much as 7% mol from well to well. Carbon dioxide and other heavy hydrocarbons have been measured at different wells at the same shale formation and been found to differ by over 10% mol. The composition variety of multiple United States shale gas locations is presented in Figure 1 and Table 1.