Multiphase Fluid

Key Takeaways

• Multiphase flow regimes in horizontal and near-horizontal pipes are classified by the spatial distribution of the phases across the pipe cross-section and along the pipe axis: stratified smooth flow (gas above, liquid below, with a smooth gas-liquid interface) occurs at low gas and liquid velocities when gravity segregates the phases and the interface is undisturbed; stratified wavy flow occurs at higher gas velocities where wind-like shear at the interface creates Kelvin-Helmholtz interfacial waves; plug flow (also called elongated bubble flow) occurs when gas pockets form as bullet-shaped bubbles (Taylor bubbles) interspersed with liquid slugs occupying the full pipe diameter; slug flow (the most common and problematic regime in production systems) occurs when the Taylor bubbles and liquid slugs are irregularly distributed, creating intermittent surges of liquid separated by gas pockets that cause pressure fluctuations, vibration, and irregular liquid delivery to the separator; annular mist flow occurs at high gas velocities where the liquid is blown as a thin film along the pipe wall and as droplets entrained in the high-velocity gas core; the regime map for horizontal flow (showing which regime occurs at each combination of superficial gas and liquid velocities) is the fundamental tool for identifying flow assurance risks in system design, with slug flow being the primary concern because of the high-amplitude pressure and liquid delivery surges it produces.
• Multiphase flow in vertical wellbores follows a different regime sequence from horizontal flow because gravity acts parallel (rather than perpendicular) to the flow direction: bubble flow (small gas bubbles dispersed in a continuous liquid phase) occurs at low GOR and low flow velocity; churn flow (a chaotic, highly disturbed flow with no stable phase distribution) occurs at intermediate velocities; slug flow (large Taylor bubbles separated by liquid slugs containing small gas bubbles) occurs at moderate GOR; and annular mist flow (continuous gas core with liquid film on the well wall) occurs at high GOR and flow velocity; artificial lift design (gas lift, electrical submersible pump, progressive cavity pump) is sensitive to the prevailing flow regime in the tubing, because each lift mechanism performs best in a specific flow regime and may operate inefficiently or fail in others; for example, ESPs are designed for bubble flow in the tubing and are damaged by slugging or high-GOR annular flow that allows gas slugs to enter the pump intake, causing head loss, vibration, and in severe cases pump seizure from overheating in a gas-locked condition where the pump intake is overwhelmed by gas.
• Pressure drop prediction in multiphase pipe flow is more complex than single-phase flow because the total pressure gradient has three components (gravity, friction, and acceleration) and each component depends on the local phase distribution (holdup), which in turn depends on the flow regime and the complex momentum exchange between phases: the gravity pressure gradient (the hydrostatic head component) equals rho_mixture times g times sin(theta), where rho_mixture is the in-situ mixture density (a function of the gas holdup, which causes the actual mixture density to be lower than the no-slip mixture density because the faster-moving gas phase has lower holdup than its volume fraction in the total flow); the friction pressure gradient depends on the wall shear stress applied by the mixture to the pipe, which is higher in slug flow (where the liquid slugs cause periodic high-velocity surges against the pipe wall) than in stratified flow; empirical correlations for multiphase pressure drop (Beggs-Brill, Mukherjee-Brill, Ansari) and mechanistic models (OLGA, LedaFlow, Schlumberger's PIPESIM) use closure equations for holdup and friction that have been calibrated against large experimental datasets but remain uncertain in conditions outside the calibration range, particularly for high-viscosity oils (greater than 100 cP), high-solids-content fluids, and large-diameter subsea pipelines where laboratory data is scarce.
• Severe slugging in subsea production systems (also called terrain slugging or riser slugging) is a specific multiphase flow instability that occurs when a subsea pipeline has a low point (catenary shape or a deliberate sag in the seabed profile) followed by a vertical riser: at low production rates, liquid accumulates in the pipeline low spot and blocks gas passage from the pipeline to the riser, building upstream gas pressure until the gas has sufficient pressure to blow the liquid slug through the riser and into the topside separator in a large, violent surge; the severe slugging cycle (fill, blowout, liquid fallback, restart) repeats at periods of 1 to 30 minutes with liquid surge volumes of 10 to 100 percent of the riser volume, creating mechanical loads on the riser, pressure and flow fluctuations that trip the separator and compressor, and in extreme cases, gas blowback into the pipeline that can displace liquid and create a flowline gas blow; severe slugging mitigation strategies include topside choking (increasing the back-pressure on the riser to push the operating point into the stable stratified flow regime, at the cost of reducing the wellhead flowing pressure and production rate), subsea separation (placing a separator on the seabed to separate phases before they enter the riser), and active slug control (using a model-predictive control algorithm to modulate the topside choke continuously to prevent slug accumulation in the pipeline while maintaining maximum production rate).
• Multiphase metering (measuring the individual flow rates of oil, water, and gas in the multiphase stream without physically separating the phases) is a growing technology area driven by the cost and space constraints of offshore production systems that cannot accommodate full three-phase test separators for every producing well: multiphase meters (Roxar, Pietro Fiorentini, Weatherford, TechnipFMC) use combinations of venturi differential pressure (which measures the total mixture flow rate), gamma-ray absorption (which measures the water-liquid ratio by the differential attenuation of gamma radiation through oil-water-gas mixtures), and microwave or capacitance sensors (which measure the water-in-liquid ratio) to compute the individual phase flow rates from measured electrical and nuclear signals without physical phase separation; the accuracy of multiphase meters (typically 2 to 5 percent relative error on each phase rate) is lower than that of a full test separator (less than 1 percent), but the cost savings from eliminating the separator (particularly for subsea wells where a full separator would cost tens of millions of dollars) and the ability to provide continuous (rather than periodic) well allocation data justify the accuracy compromise for many production measurement applications.