Unload

Key Takeaways

• Critical flow rate for liquid unloading (Turner's critical velocity) defines the minimum gas velocity required to transport liquid droplets upward in a gas well tubing string, below which liquid falls back and begins to accumulate in the wellbore: Turner et al. (1969) developed the widely used critical velocity correlation vt = 5.62 x [(sigma x (rho_L - rho_G))^0.25] / rho_G^0.5, where vt is the critical velocity in ft/s, sigma is the liquid surface tension in dynes/cm, rho_L is the liquid density in lb/ft^3, and rho_G is the gas density in lb/ft^3; the corresponding critical gas rate Qc (in MSCF/day) for a given tubing ID is calculated from the critical velocity and the tubing area, providing the minimum flow rate below which the well will begin to load up with liquids; for a typical gas well producing from a 2-7/8 inch tubing (2.441 inch ID) with water and 1,000 psi wellhead pressure, the critical rate is approximately 300-500 MSCF/day, meaning that the well must produce above this rate to naturally transport its produced water to surface; as a well depletes and the reservoir pressure and production rate decline, the production falls below the critical rate, liquid begins to accumulate, the backpressure from the accumulated liquid further reduces the gas rate, which causes more liquid accumulation, creating a positive feedback loop (liquid loading spiral) that can progress from reduced production to complete flow stoppage (well death) in weeks to months without intervention; the Turner critical velocity correlation was derived for surface tension and density typical of water-gas systems at elevated tubing pressures, and modified correlations (Li et al., 2001; Belfroid et al., 2008) provide better accuracy for different fluid systems and wellbore geometries.
• Plunger lift for well unloading uses a free-moving cylindrical plug (the plunger) that travels up and down in the production tubing between the liquid accumulated at the bottom of the well and the surface production facility, acting as a mobile piston that pushes accumulated liquid slugs to surface on each upstroke using the energy stored in the compressed gas in the tubing and casing annulus: when the well is shut in, liquid accumulates at the bottom of the tubing, gas pressure builds in the casing annulus, and the plunger sinks (falls through the gas above the liquid slug) to the bumper spring at the bottom of the tubing; when the surface motor valve opens, the casing gas pressure acting across the plunger's sealing surfaces propels the plunger upward through the liquid slug, pushing the liquid to the surface while the plunger's wiper rings provide a partial seal that prevents gas from bypassing the plunger; the arriving liquid slug is produced to the sales line or separator, the plunger arrives at the surface lubricator with a characteristic spike in tubing pressure that confirms plunger arrival, the motor valve closes, and the cycle repeats; plunger lift is an intermittent artificial lift method that requires cycling the well between closed (building casing pressure) and open (producing the liquid slug) phases, with the cycle time and flow rate optimized to maximize liquid recovery per unit time; effective plunger lift requires a minimum gas-liquid ratio (typically 300-500 scf per barrel of liquid minimum to provide sufficient energy for the upstroke) and a minimum casing-to-tubing pressure differential to overcome the weight of the liquid slug above the plunger, limiting its application to wells with some residual reservoir energy.
• Velocity strings (production tubing size reduction) for liquid unloading install a smaller-diameter tubing string (typically 1-1/2 to 2-3/8 inch OD) inside the existing production tubing to increase the gas velocity above the critical transport rate at the current production rate, allowing the well to naturally unload liquids that could not be transported at the lower velocity in the larger original tubing: for the same gas production rate, a smaller tubing ID increases the velocity as the cross-sectional area decreases (velocity = volumetric flow rate / area, so reducing the ID from 2.441 to 1.380 inches (2-7/8 to 1-3/4 inch tubing) increases the velocity by approximately 3 times for the same gas rate); this velocity increase may be sufficient to move the well from below the Turner critical rate to above it, allowing natural continuous liquid transport; velocity strings are a cost-effective intervention for wells whose production rate has declined below the critical rate for the original tubing but is still sufficient to transport liquids in a smaller tubing, and the installation can be performed on a slickline or coiled tubing unit without requiring a workover rig; the disadvantage of a velocity string is the increased friction pressure from the smaller tubing diameter, which increases the flowing wellbore pressure (reduces the drawdown pressure on the formation) and may further reduce the gas production rate, potentially requiring a delicate balance between the velocity improvement and the pressure restriction; in practice, velocity string design requires tubing performance curve analysis (IPR versus VLP, inflow performance relationship versus vertical lift performance) to determine the new stable production point with the smaller tubing and to confirm that the reduction in tubing size improves rather than worsens the total liquid recovery.
• Foam injection (surfactant injection) for liquid unloading reduces the surface tension of the produced water and condensate liquids, lowering the Turner critical velocity and allowing the well to transport liquids at lower gas rates that would normally cause liquid loading: liquid surfactants (anionic, cationic, or nonionic detergents formulated for compatibility with the reservoir brine chemistry and the wellbore materials) are injected into the wellbore through a capillary injection string, through a coiled tubing injection system, or as batch treatments dropped in solid stick form through the wellhead; the surfactant reduces the surface tension of the liquid from the normal value (approximately 70 dynes/cm for water) to 20-40 dynes/cm, which reduces the Turner critical velocity by approximately 30-50% according to the sigma^0.25 dependence in the critical velocity equation; the foam created by the gas-liquid interaction in the presence of the surfactant also provides additional liquid transport assistance by creating a lighter, lower-density foam column that can be lifted at lower gas velocities than the equivalent volume of unfoamed liquid; surfactant treatment is the lowest-cost unloading method available (chemical cost of $500-$2,000 per treatment versus $50,000-$200,000 for a plunger lift installation or velocity string workover) and is effective for wells that are only marginally loaded (liquid rate not too high and gas rate not too far below the critical rate), but it provides less lift assistance than mechanical methods for severely loaded wells and requires regular retreatment as the surfactant is produced out of the wellbore.
• Nitrogen or gas lift for unloading newly completed wells removes kill fluid or completion fluid injected into the wellbore during workover or completion operations, restoring the well to production after any treatment that required a liquid-filled wellbore: after a stimulation treatment, a cement squeeze, or a plug-and-perf completion sequence, the wellbore may be filled with kill fluid (heavy salt brine or weighted mud) at a hydrostatic pressure higher than the formation pressure, requiring that the kill fluid be removed before the well can produce; nitrogen injection (pumping nitrogen gas from a surface cryogenic nitrogen unit down the tubing while the wellbore contents circulate out the casing or vice versa) is the primary method for assisting formation pressure to displace the heavy kill fluid when the formation pressure alone is insufficient to lift the fluid to the surface; swabbing (using a swab cup tool on a wireline to mechanically lift the liquid to the surface by the piston action of the swab on the upstroke) provides an alternative mechanical unloading method for wells that cannot take nitrogen injection; the controlled unloading procedure for newly completed wells is a critical safety operation because the formation gas that replaces the displaced kill fluid creates a progressively more flammable wellbore atmosphere at the surface, requiring that the wellhead and Christmas tree valves be sequenced carefully to direct the gas flow to the flare or separator rather than to the atmosphere, and that the unloading rate be controlled to prevent an uncontrolled blowout if the kill fluid is displaced faster than the production equipment can handle the incoming gas.