Two-Phase Separator

Key Takeaways

• The physical separation mechanism in a two-phase separator relies on gravity settling of liquid droplets from the gas phase and gas bubble disengagement from the liquid phase within a residence time sufficient for both processes to approach completion: the incoming multiphase fluid enters the separator through an inlet device (a tangential inlet nozzle, a cyclonic inlet diffuser, or an impingement baffle) that imparts centrifugal force to the flow or reduces velocity, causing initial gas-liquid separation and distributing the flow uniformly across the separator cross-section; the gas phase rises to the top of the vessel and exits through the gas outlet with a mist extractor (a wire mesh pad, a vane pack, or a cyclonic mist eliminator) that coalesces and removes liquid droplets that were carried over in the gas stream; the liquid phase accumulates at the bottom of the separator and exits through a liquid level control valve that maintains a liquid level set point sufficient for liquid residence time (the time the liquid remains in the vessel before exiting, typically 1-5 minutes) to allow entrained gas bubbles to rise out of the liquid; the separation efficiency depends on the droplet size distribution in the feed (which depends on the inlet piping configuration and any upstream pressure reduction that causes flashing), the gas velocity in the vapor space (which must be low enough that droplets settle by gravity faster than they are carried by the gas flow), and the liquid level (which must be maintained above the outlet to prevent gas carryunder into the liquid stream).
• Two-phase separator sizing is governed by the gas capacity (the maximum gas flow rate at which liquid carryover in the gas outlet stream is within specification) and the liquid capacity (the maximum liquid rate at which gas carryunder in the liquid outlet is within specification), which are determined by the vessel diameter, length, and internals design: the gas capacity is limited by the terminal settling velocity of liquid droplets in the gas stream (the velocity at which drag equals gravity for a droplet of the design retention size, typically 100-400 microns); the actual gas velocity must be below this terminal velocity by a design factor (typically 75-80% of terminal velocity) to ensure droplets settle before reaching the gas outlet; the terminal velocity depends on the gas density (which increases with pressure and molecular weight), the liquid density (which decreases with increasing temperature and GOR), and the droplet retention size specified for the application; the liquid capacity is limited by the residence time available for gas bubble disengagement, which depends on the liquid holdup volume (the volume of liquid between the low-level shutdown setpoint and the high-level alarm setpoint) and the liquid flow rate; the sizing procedure for two-phase separators is standardized in API Specification 12J (Oilfield Production Vessels) and in GPSA Engineering Data Book calculation methods that provide conservative sizing equations accounting for the standard range of oil and gas stream properties.
• Two-phase separators are classified by orientation (horizontal, vertical, or spherical) and by operating pressure (low-pressure, medium-pressure, and high-pressure), with each configuration having specific applications and advantages: vertical separators (with the gas outlet at the top and the liquid outlet at the bottom) are preferred for gas streams with high gas-liquid ratios (greater than 2,000 SCF/bbl) where the liquid handling capacity is secondary, for streams with sand or produced water that would settle in the liquid section of a horizontal vessel and require frequent cleaning, and for offshore platforms where footprint area is limited but height is less constrained; horizontal separators (with the gas outlet at one end and the liquid outlet at the other, with a gas-liquid interface running along the length of the vessel) are preferred for liquid-dominated streams (lower GOR) where residence time is the critical sizing parameter, for two-phase streams with foam tendency (horizontal vessels provide a longer liquid-gas interface for foam breaking), and for large-volume separators where fabrication as a horizontal vessel is more economical than as a tall vertical vessel; spherical separators are used for very high-pressure applications (above 2,000 psi) where the spherical shape provides the most efficient use of steel for pressure containment, but their limited liquid capacity makes them suitable only for high-GOR streams.
• Production testing of oil and gas wells uses portable two-phase test separators (often called test separators or well test packages) to measure the well's gas and liquid production rates during well testing and production logging operations: the well is flowed through the test separator at a series of choke sizes, and the gas rate is measured by a turbine meter or orifice plate on the gas outlet, while the liquid rate is measured by a positive displacement meter or a dump counter on the liquid outlet; the test separator provides the gas-liquid separation needed to make these flow rate measurements in a mobile, compact package that can be trucked to the well location, connected to the wellhead, and removed after the test is complete; combined oil and water are measured as a total liquid volume at the separator, and the water fraction (water cut) is determined by laboratory analysis of a representative liquid sample or by a BS&W (basic sediment and water) centrifuge test in the field; for gas wells with low liquid production, a two-phase test separator is fully adequate because the liquid recovered is primarily condensate (not separated water in significant quantity), and the combined liquid measurement sufficiently characterizes the well's production for reservoir management and regulatory reporting purposes.
• Subsea two-phase separators, deployed on the seabed at water depths of 300-3,000 meters, are a key technology for subsea processing systems that boost the production of deepwater wells by reducing the backpressure on the wellbore: a subsea two-phase separator receives the combined wellstream from multiple subsea wells, separates the gas from the liquid, boosts the liquid with an electric submersible pump (ESP), compresses or allows the gas to flow to a floating production platform by its own pressure, and reduces the backpressure on the producing wells by lowering the wellhead flowing pressure; the reduction in wellhead flowing pressure increases the pressure drawdown in the reservoir, increasing production rate (by moving the operating point up and to the right on the well's inflow performance relationship) and extending the economic production life of wells that would otherwise be unable to produce through the long subsea pipeline back to the platform; two-phase subsea separation is technically simpler than three-phase separation (because no water-oil interface control is required) and produces better pumping performance from the ESP (which pumps better with lower free gas content after two-phase separation) while deferring the water-oil separation to the topside facilities on the platform where gravity-based separation is straightforward and maintenance is accessible.