Abstract

A gas condensate pipeline transports gas from an onshore Gas/Oil Separation Plant (GOSP) to a Processing Gas Plant. Gas that flows into the pipeline is transported directly from the GOSP's separator after compression without any further dehydration process. As the gas temperature inside the pipeline begins to drop, water and condensate drop out from the gas. The pipeline is flowing at a rate lower than its desired flow rate. Significant liquids (condensate and water) are accumulated in the pipeline due to the low flow rate. The pipeline was found partially blocked and subsequent scraping caused a full blockage because the scraper was stopped inside the pipeline. Production data and pipeline simulation analysis showed that hydrate had formed inside the pipeline before the scraping. This paper will present the analysis results for hydrate formation in the gas condensate pipeline as well as the recommendations to prevent. Measured production data analysis and pipeline simulations were used. A pipeline multiphase dynamic simulator was used to study the pressure, temperature, and liquid holdup profile along the pipeline. Hydrate formation temperature was found to be in the range of 18 °C (65 °F) at the operation pressure, which is above the ambient winter temperature.

Introduction

In early 2007, one GOSP noted that the back pressure on the gas pipeline that transported gas from the GOSP to a gas plant increased from 240 psig to 330 psig. A request was issued to launch a scraper to eliminate a suspected blockage in the pipeline. The scraper was launched from the GOSP and stopped inside the pipeline, causing a complete blockage of flow. The gas flow was reestablished by reversing the flow direction. An Engineering Review Team was formed to evaluate the cause of the pipeline partial blockage, to conduct a detailed multiphase hydraulic study of the pipeline, and to establish longterm solutions to prevent reoccurrence.

The pipeline is partially onshore and partially offshore. Due to the low ambient temperature at winter time, pipeline operating temperature can be below the hydrate formation temperature. Water is saturated in the gas that flows into the pipeline and gas is not inhibited with any hydrate inhibitor. Water and hydrocarbon liquid accumulate in the pipeline due to lower ambient temperature. The amount of accumulated water can be very high if the gas velocity is not high enough. Hydrate was suspected to be the cause of the partial blockage as the possibility of accumulated water inside the pipeline coupled with low ambient temperature. Hydrate is an ice-like crystalline solid composed of water and gas, usually methane. It became more of an interest to the natural gas industry as early as the mid-1930s when it was determined that natural gas hydrates were blocking gas transmission lines, frequently at a temperature above the ice point1.

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