Liquid Blocking

Key Takeaways

• Retrograde condensate blocking is the most economically significant form of liquid blocking in gas condensate reservoirs, occurring when the flowing bottomhole pressure drops below the dew point pressure during production, causing the heavier hydrocarbon components (C5+ and heavier) to condense from the gas phase and accumulate as a liquid ring in the near-wellbore pore system at saturations that can exceed the critical condensate saturation: below the critical condensate saturation, the condensate is immobile and blocks gas pathways without contributing to production; above the critical condensate saturation (typically 10 to 25 percent of pore volume depending on the wetting characteristics), some condensate becomes mobile and may flow toward the wellbore, but the relative permeability to gas in the condensate-saturated zone is reduced dramatically (often by 50 to 80 percent compared to single-phase gas permeability) even when some condensate mobility exists; the economic impact of retrograde condensate blocking in rich gas condensate fields (with condensate-gas ratios above 100 bbl/MMscf) can reduce well deliverability to less than 20 percent of the theoretical single-phase gas rate, making condensate blocking one of the highest-value production engineering problems in the global gas industry.
• Water blocking from drilling or completion fluid invasion is a well-known mechanism in naturally water-wet tight gas sands where the capillary pressure required to re-mobilize the invaded filtrate is much higher than the reservoir drive pressure, causing a permanent reduction in gas productivity that is not corrected by drawdown alone: when water-based drilling mud filtrate invades a tight gas sand (with permeabilities of 0.001 to 0.1 millidarcy) during the overbalanced drilling of a horizontal well, the filtrate saturates the near-wellbore pore system and must be displaced by gas flow before the well can produce at its native permeability; in sands with pore throat radii of 0.1 to 1 micron and water-gas interfacial tension of 50 to 72 mN/m, the capillary pressure to displace the blocking water (2*IFT*cos(theta)/r, where theta is the contact angle and r is the pore throat radius) may exceed 500 psi, which cannot be overcome by typical reservoir drive pressures in low-pressure tight gas plays; this water blocking damage can reduce initial production rates by 50 to 90 percent and is the primary motivation for using oil-based or synthetic-based drilling muds in tight gas horizontal wells.
• Liquid loading in gas wells is the gas production impairment that occurs when the gas velocity in the wellbore tubing falls below the minimum velocity required to lift produced water and condensate droplets to surface, allowing liquid to accumulate in the wellbore, increase the hydrostatic backpressure on the formation, and progressively reduce inflow until the well may die entirely: the minimum critical gas velocity for liquid unloading (Turner's critical velocity) is calculated from a force balance between the gas drag force on a droplet and the gravitational and surface tension forces retaining it, giving a critical velocity of approximately 5 to 10 ft/s depending on tubing size and liquid properties; as reservoir pressure declines over the life of a gas well, the produced gas rate eventually falls below the rate needed to maintain the critical velocity in the available tubing size, and liquid begins to accumulate; remediation options include velocity string installation (smaller-diameter tubing to maintain critical velocity at lower rates), plunger lift (mechanical liquid expulsion), surfactant injection to reduce droplet surface tension, and compressor installation to lower wellhead backpressure and increase velocity.
• Remediation of near-wellbore liquid blocking in tight gas sands uses solvent injection, surfactant treatment, or gas injection to restore gas relative permeability by displacing or reducing the saturation of the blocking liquid: methanol injection (pumped down the tubing and into the perforations) is the most common field treatment for water blocking in tight gas wells, exploiting methanol's miscibility with both water and hydrocarbons and its ability to reduce water-gas interfacial tension by mixing with the trapped water phase; fluorocarbon surfactants (which reduce the surface energy of reservoir grains and convert them from water-wet to partially gas-wet, lowering the capillary retention of water) have been applied as a more permanent treatment in some tight gas basins (Pinedale Anticline, Piceance Basin) where water blocking from completion fluids is the dominant damage mechanism; cyclic gas injection (huff-and-puff) can re-vaporize retrograde condensate in the near-wellbore region by increasing pressure above the dew point, mobilizing the condensate and allowing it to flow into the wellbore when the well is returned to production.
• Prevention of liquid blocking during well completion and workover operations in tight gas reservoirs requires the selection of completion fluids with low water phase activity (to minimize osmotic invasion), low filtrate volume (to minimize the volume of blocking fluid entering the formation), and low interfacial tension with natural gas (to minimize the capillary retention force on any filtrate that does enter); potassium chloride polymer muds, non-aqueous completion brines (formate brines with water activities near 0.8), and oil-based completion fluids are used depending on the specific formation sensitivity and regulatory constraints; formation damage testing using native reservoir core plugs saturated with formation water and tested under reservoir stress conditions (capillary pressure curves, relative permeability measurements, and cleanup simulations) is the industry standard method for selecting the least damaging completion fluid and predicting the severity of liquid blocking damage before committing to a fluid system in a multi-well development program.