Entrained Gas

Key Takeaways

• Entrained gas versus kick gas — understanding the distinction determines whether the driller takes well control action or continues routine drilling — a kick is formation fluid (gas, oil, or water) that has invaded the wellbore because formation pressure exceeds bottomhole hydrostatic pressure, requiring immediate well control response; entrained gas is mechanically incorporated air or formation gas that entered the mud through non-flow pathways and does not require well control action beyond operating the degassers; the critical diagnostic indicators are: entrained gas produces a gradual, diffuse increase in pit volume as gas slowly works its way up the annulus and liberates at the surface, while a kick produces a more rapid and concentrated pit volume gain; entrained gas typically does not cause consistent flow when the pumps are shut down, while a kick shows sustained flow at the surface when the pumps are off; the drilling returns show background gas from formation cuttings (detected by the mud log gas chromatograph) during normal drilling, while a kick shows dramatically elevated gas readings and potentially heavier hydrocarbons (C3 and above); misinterpreting background entrained gas as a kick causes unnecessary nonproductive time from false well control events; misinterpreting a genuine kick as entrained gas is a catastrophic error that allows the kick to grow until it becomes an uncontrolled blowout.
• Oil-based mud degassing at surface is a significant source of entrained gas that is inherent to OBM systems rather than indicative of a formation gas problem — oil-based muds contain dissolved gas (both formation gas from circulating through gas-bearing formations and nitrogen or methane that dissolves in the oil base fluid under bottomhole pressure) at concentrations determined by Henry's Law; as the mud returns to surface through the riser and choke line, the pressure decreases and gas comes out of solution as small bubbles entrained in the mud matrix; this degassing is visible as surface gas evolution from the possum belly (the returns header at the top of the shale shakers), and the volume of gas liberated increases with the amount of formation gas the mud has been exposed to at depth and with the base oil's gas solubility characteristics; synthetic base fluids (esters, poly-alpha-olefins) have lower gas solubility than conventional mineral oils at the same bottomhole conditions, producing less entrained gas during degassing at surface; managing OBM degassing requires ensuring that the mud-gas separator is properly sized and operational, that the degassed mud is thoroughly de-gassed before returning to the suction pit, and that the pit crew is not alarmed by routine degassing volumes that are characteristic of OBM operations in gas-bearing formations.
• Entrained gas effects on equivalent circulating density (ECD) calculations can create discrepancies between measured downhole pressures and surface-computed ECD values — in a drilling fluid containing entrained gas, the bulk density of the fluid in the annulus is lower than the density of the gas-free mud because the gas bubbles occupy volume and contribute negligible weight; the actual annular pressure gradient (and therefore the actual ECD at any point in the wellbore) is lower than what the surface calculations predict from the gas-free mud density; in wells drilled with a narrow margin between pore pressure and fracture gradient, this ECD discrepancy can cause the driller to believe the well is overbalanced (based on the calculated gas-free ECD) when it is actually approaching the minimum overbalance required to prevent influx; downhole pressure-while-drilling (PWD) sensors that directly measure the annular pressure at the drill collar position provide the actual bottomhole ECD regardless of gas entrainment in the annulus above the sensor, and comparing PWD readings to surface-calculated ECD is one method for detecting significant gas entrainment that is reducing effective hydrostatic pressure below the calculated value.
• Vacuum degassers are more effective than atmospheric (poor boy) degassers for removing fine entrained gas bubbles from viscous oil-based muds — the atmospheric degasser (poor boy degasser) works by passing the returned mud over a series of baffles in an open vessel, allowing gas bubbles to rise to the surface by buoyancy and escape; this works well for large bubbles (greater than 1-2 mm diameter) in low-to-moderate viscosity water-based muds, but is less effective for very fine bubbles (less than 0.5 mm) in high-viscosity oil-based muds, where the buoyancy force on the small bubble is insufficient to overcome the viscous drag force within the residence time available in the degasser vessel; vacuum degassers apply a partial vacuum (typically 20-25 inches of mercury below atmospheric) to the mud surface in a closed vessel, dramatically reducing the partial pressure of gas above the mud and promoting bubble growth and release; the combination of vacuum and turbulent agitation (some designs use rotating paddles or spray nozzles) effectively removes 90-98% of the entrained gas even from high-viscosity oil-based muds; offshore deepwater operations where OBM is standard and mud volumes are large typically run vacuum degassers as the primary degassing equipment, with the atmospheric mud-gas separator handling the bulk separation of large free gas slugs before the vacuum degasser handles the fine residual entrained gas.
• MWD mud pulse signal quality is significantly degraded by entrained gas because gas compressibility attenuates pressure pulses in the mud column — the mud pulse telemetry used by MWD tools to transmit formation and directional data to surface works by generating pressure pulses in the circulating mud that travel up the drill string interior at the acoustic velocity of the mud (approximately 4,000-5,000 feet per second for typical weighted water-based muds); gas entrained in the mud increases the compressibility of the fluid, reducing the acoustic velocity and increasing the attenuation of pressure pulses per unit distance traveled; in severe gas-cut mud conditions (greater than 5-10% gas by volume in the mud column), MWD data transmission can become erratic or cease entirely, because the pressure pulses generated by the downhole tool are damped to below the detection threshold of the surface pressure sensors before they reach the top of the drill pipe; this loss of MWD communication is operationally inconvenient in any well but is particularly problematic in horizontal wells being geosteered in real time, where loss of the gamma ray and directional data for even a few hours can result in the well exiting the target formation without the driller being aware until the change in lithology becomes apparent from surface indicators.