Natural gas accepted into the pipeline at receipt points is subject to gas quality specifications to ensure that downstream laterals and mainlines are not subjected to operational upsets, and that the integrity of the pipeline and related facilities is not compromised. One of the specifications is the maximum hydro-carbon dew point (HCDP) at the pipeline operating pressure. Occasionally, gas plants encounter operational upsets that result in a higher HCDP. If the HCDP exceeds the ground temperature, condensation of heavier hydrocarbon can potentially occur along the lateral. Ideally, after an upset has been detected and the producer has been shut in, the lateral would be pigged to remove the condensed hydrocarbons. However, if the lateral is unpiggable, the only way to remove the liquids is to evaporate them into a flow of dryer gas. The present paper compares two potential courses of action which may be taken after a high HCDP is detected at a receipt point on an unpiggable line: (a) flowing dry gas from the producer after the source of upset is corrected, or (b) pulling dryer gas back from the operator’s mainline through the lateral to the producer. In order to determine the most appropriate course of action for a given upset, the state of the lateral during and after the upset must first be accurately quantified. In the present paper, the state was modelled based on the governing equations of fluid flow including heat transfer and condensation, the GERG-2008 equation of state, and empirical liquid-hold-up equations. The effect of flow parameters (e.g., gas composition, lateral elevation profile, ground temperature, etc.) on the upset severity is explored. Subsequently, models for forward flow and pull back are presented, and the criteria for selecting when either course of action is appropriate are discussed.

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