Gravity Segregation

Key Takeaways

• Gas-oil gravity segregation in reservoirs drives gas to the structural crest of the anticlinal trap and oil to the flank, with the gas-oil contact (GOC) position at equilibrium representing the depth at which gas and oil are in capillary-gravity equilibrium (the capillary pressure at the GOC equals zero for a flat meniscus at the gas-oil interface); during production, if the reservoir produces at a rate above the critical rate for gravity segregation (defined as the production rate at which the viscous pressure gradient from horizontal flow exceeds the gravity segregation driving force), the gas and oil move together as a mixed phase and the GOC descends uniformly as both are produced; if production is below the critical rate, gas segregates upward faster than it is drawn toward the wells and a stable free-gas phase accumulates at the top of the reservoir even in a reservoir below the bubble point (secondary gas cap formation), a phenomenon observed in steeply dipping reservoirs with high vertical permeability where gas liberated from solution rises rapidly to the crest while the oil column remains oil-saturated, reducing the GOR at the producing wells and extending the oil production life above the GOR that would be expected from simple primary depletion.
• Water-oil gravity segregation in waterfloods determines the vertical sweep efficiency of the flood: if the waterflood is conducted below the critical rate for stable displacement (the rate at which viscous forces overcome the tendency for the denser water to underride the oil), water slumps to the bottom of the reservoir at the injection face and moves preferentially along the base of the pay zone rather than uniformly displacing oil from the full vertical interval, creating a water tongue at the base of the reservoir that breaks through at the producing well while oil remains stranded in the upper part of the pay zone; this gravity underriding (also called gravity tonguing or viscous fingering in the vertical direction) is more severe in thick reservoirs with high vertical permeability, where the buoyancy of the water relative to the oil is sufficient to cause significant vertical segregation within the residence time of the water slug in the reservoir; countermeasures to gravity underriding include injecting the water at reduced rates (to lower the viscous-to-gravity force ratio), perforating the injection wells preferentially in the upper part of the reservoir (to inject water into the oil zone rather than below it), and using polymer floods (which increase the water viscosity to reduce the mobility ratio and stabilize the displacement front against both viscous fingering and gravity underriding).
• Gravity segregation in gas-injection EOR processes (natural gas, CO2, or nitrogen injection for miscible or immiscible displacement) causes the injected gas to override the oil column and move to the structural crest rather than displacing oil by piston-like displacement through the vertical reservoir interval; the gas override is driven by the large density contrast between the injected gas (density of 0.1 to 0.5 g/cc at reservoir conditions) and the reservoir oil (density of 0.6 to 0.85 g/cc), which creates a strong buoyancy force that rapidly segregates the gas to the top of the injection interval; water-alternating-gas (WAG) injection mitigates gas gravity override by periodically injecting water (which has a higher density and viscosity than gas) to gravity-stabilize the gas-water-oil system, with the water slug settling below the gas and providing a denser, slower-moving front that sweeps the lower part of the reservoir interval while the gas sweeps the upper part, improving the total vertical sweep efficiency compared to continuous gas injection; gravity-stable gas injection (injecting gas at a rate below the critical rate for gravity-stable displacement, calculated from the Dumore criterion as the rate at which the gravity number exceeds 1.0) can achieve near-complete vertical sweep efficiency but requires impractically low injection rates for most commercial fields, and is only feasible in highly dipping reservoirs (greater than 20 degrees) where the strong gravity component provides a natural stabilizing force for the gas-oil displacement.
• Wellbore gravity segregation in shut-in or low-rate producing wells causes the fluid column in the production tubing to stratify by density, with gas rising to the top and water (or dense brine) settling to the bottom; in gas-lifted wells that are shut in for extended periods, the gas lift gas (which was injected into the tubing to reduce the hydrostatic pressure and lift the fluid to surface) rises out of the liquid column and escapes through the gas lift valves back to the casing annulus, leaving the tubing filled with heavy liquid (oil and water) that exceeds the reservoir pressure when the well is restarted and must be displaced by the reservoir pressure before the well can flow; in gas wells producing liquid condensate or water through the tubing, gravity segregation during shut-in periods can cause liquid to settle to the bottom of the wellbore (liquid loading), with the liquid column then requiring the reservoir pressure to exceed both the hydrostatic head of the liquid plus the wellhead pressure when the well is put back on production, potentially preventing the well from re-establishing flow (liquid-loaded well failure); production management strategies for liquid-loaded gas wells (intermittent gas lift, velocity strings, plunger lift) are designed to periodically remove the liquid slug that accumulates by gravity segregation before it becomes too large for the reservoir pressure to lift.
• Gravity segregation in surface production separators and gas processing facilities is the operating principle of three-phase separators (which separate gas, oil, and water using residence time and gravity): the incoming multiphase production stream is decelerated by an inlet diverter at the separator vessel entrance, and the three phases segregate by gravity (gas rises to the top where it exits through the gas outlet, oil occupies the middle liquid layer where it exits through the oil weir, and water settles to the bottom where it exits through the water outlet) as the fluid moves horizontally through the vessel; the separator residence time (the volume of the vessel divided by the total liquid inlet flow rate) determines the extent of gravity segregation achieved before the fluid exits, with minimum residence times of 1 to 3 minutes for gas-oil separation and 3 to 10 minutes for oil-water separation (because the lower density contrast between oil and water results in slower gravity settling than the large gas-liquid contrast); emulsified produced fluids (where the oil-water interface is stabilized by surface-active compounds from the formation, preventing gravity segregation on the timescale of the separator residence time) require chemical demulsifier treatment and in some cases electrostatic coalescence (applying a high-voltage electric field across the oil-water layer to coalesce water droplets) to overcome the emulsion stability and allow gravity segregation to work.