Application Of Transient- Multiphase-Flow Technology
Authors: Erickson Dale D. , Mai Michael C. 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Introduction
The challenges associated with multiphase flow are as old as the oil business itself. The natural flow from most wells consists of some mixture of oil, gas, and water. Historically, separators were placed as close to the wellhead as possible to avoid problems associated with multiphase-flow behavior. However, as production has moved into more hostile environments and project and operating philosophies have changed, use of multiphase transport in oil and gas production operations has increased. For example, in the production scenario in Fig. 1, all production (gas, condensate, and water) from the subsea wells and the wellhead platforms is transported commingled to the central platform. At the central platform, liquid/gas separation is performed so that the gas can be compressed and the liquid pumped. The fluids (liquid and compressed gas) are then remixed and transported as a multiphase mixture in a single pipeline to shore. Onshore, the fluids are separated to sales specification. In this scheme, methanol may be needed at the wellhead to prevent formation of hydrates. The methanol is removed from the water phase onshore and sent back offshore for reuse. If methanol is not required in the infield network, the water can be separated on the central platform and disposed of offshore.
To make production scenarios like this one both feasible and reliable, transient-multiphase-flow modeling is used in many different ways. This paper provides brief descriptions of these techniques that are based on our experience with more than 200 individual studies of multiphase pipelines and related facilities worldwide. These applications include conventional offshore, deepwater, arctic, and desert production and transportation systems.

Line Sizing
Selecting the line size for a single-phase pipeline is relatively direct. The greatest anticipated flow rate should be established, the available pressure driving force should be determined, and pressure-drop relationships should be used to select a line size large enough to transport the required flow. Typically, economics may drive the line size to still greater values to accommodate future production or third-party fluids.
The line-sizing problem in multiphase flow is more problematic because bigger is not necessarily better. Fig. 2, which shows the envelope of operability, explains this concept. The envelope has three main curves. The snake-like curve shows how production is expected to change with water cut (as the field matures and additional wells are brought on line). These production numbers reflect total liquid flow rates. The upper curve establishes the throughput limit of the pipeline on the basis of pressure-drop constraints, as governed by expected flowing wellhead pressures. The region below the lower curve establishes the production and water-cut combinations where terrains lugging occurs. The region between the curves is the envelope of operability. In this case, production over most of the field life is inside the envelope. Increasing the line size moves the envelope up, and decreasing the line size moves it down. In this way, operational impacts of different line sizes can be assessed.
The key to making the envelope of operability a reliable design tool is to use an accurate dynamic model to calculate the boundaries. In preliminary engineering, a design engineer often uses steady-state simulators (or other correlations based on low-pressure, small-diameter, air/water laboratory data).These relationships should be used with caution. In one case that ween countered while working on a subsea pipeline, transient-model predictions for the pipeline pressure drops were 30% greater than the steady-state-model predictions (with similar differences in predicted liquid holdups). On the basis of the transient-model results, the line size was reduced by 2 in. from the size initially recommended on the basis of steady-state-model results. Field data subsequently confirmed that the transient-model predictions were within 8% of the actual values. If the larger line size had been installed, the pipeline would have been in the terrain-slugging region under normal flowing conditions, creating substantial operational problems.

Line Pack/Unpack
Gas is difficult to store in large quantities unless converted to liquefied products. Therefore, offshore gas production typically is regulated to match onshore demand. Because of the storage (compressibility) and resistive properties (friction loss) of the pipeline, a time lag occurs between changes in the gas flow rate into the pipeline and corresponding changes in the gas flow rate out of the pipeline. To maintain deliveries during short offshore shutdowns, the pipeline may be operated in a packed condition. "Packed" in this sense refers to the additional gas that can be stored in the pipeline by increasing operating pressures. These operating pressures are higher than the driving force required simply to transport the gas to shore given the minimum allowable arrival pressure. Moreover, an oversized line has been used in some cases to provide the line packing necessary to ensure uninterrupted onshore delivery during temporary offshore shutdowns. In multiphase systems, this issue becomes more complicated because the liquid reduces the volume available for gas compression. Furthermore, increases in flow rate can produce the intended gas volumes but may also yield problematic quantities of liquid.