This paper describes the development of onshore brown field gas compression projects, with production from many hundreds of wells in remote locations. Gas is produced from both sweet and sour reservoirs, with differing decline characteristics and fluid compositions. The paper describes the impact of flow assurance design on the field development plan. The potential for liquid management difficulties are discussed, and a novel liquid management mitigation solution is proposed.

The initial investigation used maps to identify the hydraulic optimum locations for gas compression plants (GCPs) in congested areas, followed by site visits. A number of GCPs were based on gas production rate, field location, gas plant capacity and compression power. Design was performed with remit to reuse as much of existing facilities as possible.

Uncertainties in multiphase pressure and hold-up predictions on aging pipes required a conservative approach to hydraulics. Sensitivity analyses were performed on critical parameters.

The pipeline network design was refined through a cycle of site visits to obtain pipeline corridors and GCPs land use permits. Diameters were optimized to lower liquid accumulation and mitigation implemented against uneven split of liquid flow through existing twin pipelines.

Some pipelines upstream of GCPs were discovered to experience high levels of liquid accumulation. This is in agreement with operating experience. "U-bend" topography allows severe liquid accumulation and potential blockage, requiring frequent scraping for liquid management. The proposed solution is comprised by Liquid Separation Stations (LSSs). The LSSs are designed to remove bulk liquids at low points, which are transported via separate liquid pipelines to the GCPs slug catchers (SCs), then onwards to the gas plant.

With remote location of LSSs, the design philosophy adopted for design was application of piping components according to ASME B31.8 code, instead of ASME vessel code (and the resultant required appurtenances). This allows very basic gas/liquid separation; and the ability to immediately drain liquids from the separator to maintain normal liquid levels. Consequently, with the ability to drain at rates within an adequate uncertainty factor, significant residence time in the LSS is not necessary, allowing the sizes to be kept within the confines of B31.8 code.

Uncertainties in system design inputs and multiphase flow prediction in brownfield developments are highlighted. The proposed novel use of piping code to develop remote field separation for liquid management is discussed. This mitigation offers benefits of reducing operational issues associated with frequent scraping and liquid blocked pipelines.

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