Gas Anchor

Key Takeaways

• Gas lock in sucker rod pumps occurs when the fraction of free gas in the pump barrel at the end of the downstroke exceeds the compressibility of the gas, preventing the pressure inside the barrel from dropping below the standing valve cracking pressure when the plunger begins the upstroke: during the downstroke, the traveling valve opens and allows the fluid above the plunger to fall through the plunger, while the standing valve closes and the fluid in the barrel is compressed; during the upstroke, the traveling valve closes and the standing valve should open when the barrel pressure drops below the standing valve cracking pressure (approximately equal to the pump intake pressure), but if the barrel is filled with compressible gas, the gas compresses during the downstroke rather than opening the traveling valve, and when the plunger moves up, the gas re-expands and the barrel pressure may never drop sufficiently to open the standing valve; the well continues pumping (the beam unit strokes up and down) but no liquid is produced — the pump is gas-locked; the fraction of the pump displacement volume that must be occupied by free gas for gas lock to occur decreases at higher pump setting depths (where the pump intake pressure is higher) and increases at shallower setting depths (where the pump intake pressure is lower and less compression is required to drop the barrel pressure below the standing valve cracking pressure); gas anchors prevent gas lock by removing most of the free gas before it enters the pump barrel, ensuring that the fluid entering the barrel is predominantly liquid with a free gas fraction below the gas lock threshold.
• Gas anchor separation efficiency — the fraction of the free gas at pump intake depth that is prevented from entering the pump barrel by the gas anchor — depends on the gas anchor design, size, and setting relative to the perforations and the pump: the key design parameter is the downward fluid velocity in the gas anchor annulus (the separation section), which must be less than the terminal rise velocity of gas bubbles in the produced liquid for separation to occur (if the downward fluid velocity exceeds the bubble rise velocity, gas bubbles are swept into the pump intake along with the liquid and the anchor provides no separation); the terminal rise velocity of gas bubbles in produced oil depends on the bubble size (larger bubbles rise faster), the oil viscosity (higher viscosity reduces bubble rise velocity), and the oil density; for typical oilfield conditions (bubble diameter 1-5 mm, oil viscosity 5-50 centipoise), the terminal bubble rise velocity is 0.1-1.0 cm/s, and the gas anchor annular area must be large enough that the downward liquid velocity at the maximum anticipated production rate is below this terminal velocity; gas anchor separation efficiency for properly designed anchors in vertical wells is typically 80-95% for moderate gas-liquid ratios (less than 500 SCF/bbl at pump conditions) and decreases to 40-70% for high gas-liquid ratios (greater than 2,000 SCF/bbl), where the gas volume is too large for complete separation in the practical gas anchor dimensions.
• Pump submergence — the depth of the pump setting below the dynamic fluid level in the well — is the primary operational parameter that controls whether a gas anchor is necessary and how effective it will be: at pump settings with high submergence (the pump is set 500-1,500 feet below the dynamic fluid level), the pump intake pressure is well above the solution gas-oil ratio (GOR) saturation pressure, gas remains in solution in the oil, and the pump handles single-phase liquid with no gas separation required; as the reservoir depletes and the dynamic fluid level drops, or if the well is completed with insufficient casing capacity, the pump submergence decreases and the pump intake pressure approaches or falls below the bubble point of the produced oil, causing gas to come out of solution and form free gas at pump intake depth; when submergence drops below approximately 200-500 feet (depending on the oil bubble point and the pump intake pressure required to maintain liquid production), free gas in the pump becomes a practical problem requiring a gas anchor; increasing pump submergence (by lowering the pump setting depth, or by maintaining reservoir pressure through water injection) is the most effective long-term solution to gas interference, but when submergence cannot be increased further (because the pump is already set near the perforations), a gas anchor is the mechanical solution for managing the gas that enters the wellbore at pump depth.
• Rotary-type gas separators (a powered variant of the passive gas anchor concept) use centrifugal force rather than buoyancy to separate gas from liquid at the pump intake, and are used in electric submersible pump (ESP) installations where the passive gas anchor is not effective (because ESPs require a continuous liquid phase to avoid gas locking) and in high-volume sucker rod pump wells with extreme gas-liquid ratios: the rotary separator is driven by the sucker rod string rotation (in rod-pump applications) or by the ESP motor (in ESP applications) and creates a centrifugal field that accelerates gas toward the central axis (where it is diverted upward and out of the pump intake stream) while the denser liquid is flung toward the separator wall and flows into the pump intake; rotary separators achieve separation efficiencies of 95-99% for free gas at pump depth, significantly higher than passive gas anchors for the same flow conditions, but add cost and mechanical complexity to the completion; the rotary separator is most commonly used in ESP installations where the consequences of pump gas lock (ESP wear from dry running, impeller damage, and motor overheating from the loss of liquid cooling) are more severe than for sucker rod pumps, and where the higher production rates of ESPs make the gas separation problem more acute than in lower-rate rod pump wells.
• The position of the gas anchor perforations relative to the producing casing perforations is a critical design parameter in new well completions: a gas anchor set above the producing perforations draws its separation fluid from the annular column between the production perforations and the pump intake, allowing the gas that rises from the perforations to escape into the tubing-casing annulus above the anchor body before being drawn into the pump; a gas anchor set below the perforations (the ideal position for maximum separation) draws its separation fluid from the formation directly, but this requires the pump and gas anchor to be positioned below the perforations, which is not always practical if the perforations are near the bottom of the casing string; the "dip tube" gas anchor (in which a long perforated tube extends from the gas anchor body down into the rathole below the perforations) provides an approach intermediate between these extremes by allowing liquid to be drawn from below the perforations even when the pump body is set above them; matching the gas anchor design to the specific well geometry (perforation depth, rathole depth, casing diameter, pump setting depth, and expected production rate) is the key to effective gas separation in challenging high-GOR producing wells.