The low flowrate operation of gas/condensate pipelines can lead to significant liquid accumulation, which can give rise to the need for operational procedures to control the amount of build-up and of liquid sweep-out during flowrate increases. When water is also present in the fluid stream the operation is more difficult to predict using classical two-phase flow models, and there can be a significant impact on the flowing capacity, the flexibility of operations, and the mitigation of corrosion and hydrate problems. Field data from an operating wet gas pipeline is used to illustrate the limitations of present two-phase models, and to highlight areas of concern, which gave rise to the construction of a simple experimental two-phase and three-phase flow test facility. Flow pattern, hold-up, and slug characteristics are presented and compared with the predictions of a simple mechanistic model, transient two-phase, and an experimental transient three-phase computer codes. In most cases a full understanding of the hydraulic characteristics requires a transient three-phase flow simulation, for which preliminary results are encouraging. The future use of such tools could have a significant impact on wet gas pipeline operating strategies for corrosion and hydrate control, and the management of the inventory to provide flexibility of gas contract supply.
Classical multiphase flow design methods normally only consider two phases, a gas phase and a liquid phase. In oil and gas operations the hydrocarbon fluids are usually contaminated with water, which either condenses in the pipeline, or is produced from the formation as free water. Other contaminants can also exist, such as emulsion and anti-foaming chemicals as well as inhibitors for corrosion and hydrates. There may also be wax and scale inhibitors present. The concentration of most of these chemicals is usually low and can be ignored in a multiphase hydraulic analysis, apart from water, may be present at up to 95% of liquid in some oil and condensate multiphase systems. Conventional hydrate inhibitors, such as methanol, which may typically have a concentration of 10%- 40% in the water phase. It is common practice to assume that the liquid phase is a homogeneous mixture, regardless of the concentration of water/methanol, and the pseudo liquid phase properties are determined by a simple weighted average of individual liquid phase properties.
In practice segregation of the hydrocarbon and non-hydrocarbon liquid phases can occur leading to a three-phase flow in which the water containing methanol and other water based additives flows along the bottom of the pipeline and accumulates in dips. This can have a significant effect on the liquid inventory of the pipeline as the non-hydrocarbon liquid phase is more dense and gives rise to higher holdups than predicted by the pseudo liquid phase models. This has a number of implications for wet/gas pipeline design and operations because (1) operation at low gas velocities can cause liquid to accumulate which, when swept-out by a transient gas increase causes, problems for processing plants normally designed for low water production rates; (2) inhibitor storage volumes may be underestimated due to the longer residence time in practice and this may also have implications for threshold inhibitors; (3) corrosion protection may be inadequate if stagnant water pools occur and inhibitor mobility is insufficient; (4) the segregation effects can influence the frequency of slugging that can occur in gas/condensate flowlines, and may have implications for slug catcher sizing.
Fig. 1 illustrates the likely flow patterns in a undulating wet gas pipeline operating under low flowrate conditions. The inclination angles are typically +/-1 or less, and the holdups are in the region of a few percent in the down sloping sections which operate predominantly in stratified flow. Slugs are generated at the dip and this leads to a higher liquid holdup of around 50% in the uphill sections. P. 611^