As onshore oil & gas production begins to recover from the recent industry downturn, pipeline gathering system infrastructure is being expanded beyond the original design intent. Gathering system flow rates are increasing to handle additional production, supplementary pipework is being added at the edges of the gathering systems to accommodate new drilling, and some systems are considering switching from predominantly single-phase flow to multiphase flow. Hence, accurate multiphase flow modeling is required to make key project decisions because small amounts of multiphase flow can significantly impact pressures in large gathering systems.

Recent experience on multiple, low pressure (< 20 bar) onshore gathering system projects has found a wide discrepancy between the model-predicted and the field-measured system pressures. Of particular concern are liquid (oil + water) systems, which have been observed in modeling to under predict pipeline pressure drop. This is a significant issue because the pressure margins in onshore gathering systems are tight and, in some instances, a ±1 bar difference in expected pressures can dictate how the system is operated.

The primary purpose of this paper is to present case studies from three different US onshore gathering systems (each in different US shale basins), comparing the field-measured pressures with multiphase flow model pressures calculated using commercially-available software packages. OLGAS HD, Beggs and Brill, and TUFFP are some of the multiphase flow correlations that are considered in this analysis. The various case studies include predominantly single-phase gathering systems and a multiphase liquid (oil + entrained gas + water) gathering system.

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