Internal Flash

Key Takeaways

• Bubble point pressure and its relationship to internal flash determines at what depth in the production tubing a single-phase reservoir oil begins to release gas and become a two-phase mixture during production, with the bubble point marking the transition between single-phase and two-phase flow that fundamentally changes the well's deliverability and flow behavior: at reservoir conditions above the bubble point, the oil flows as a single compressed liquid containing all its dissolved gas, and the pressure drop along the tubing string causes only viscous friction losses; when the tubing pressure drops below the bubble point (which occurs at a specific depth in the producing tubing that depends on the tubing pressure gradient and the fluid's bubble point pressure), gas begins to evolve from the oil and internal flash initiates; below the flash depth, the fluid is a two-phase gas-liquid mixture with dramatically different flow behavior including higher velocity (the gas phase expands and accelerates as pressure drops further up the tubing), lower density (reducing the hydrostatic head and aiding lift), and higher frictional pressure loss (two-phase friction is higher than single-phase for the same mass flow rate); the location of the flash point in the tubing is important for artificial lift design: for gas lift wells, the gas injection depth is optimized to be just below the natural flash depth so that the injected gas supplements the naturally flashing gas and provides the required energy to lift the liquid to surface; for ESP-lifted wells, the pump is set deep enough below the flash depth to ensure that the pump intake receives single-phase liquid without free gas that would cause cavitation and reduce pump efficiency.
• Cavitation from internal flash in control valves and chokes occurs when the local pressure drops below the vapor pressure of the liquid at the orifice vena contracta (the point of maximum velocity and minimum pressure in the flow through the restriction), causing a portion of the liquid to flash to vapor bubbles that then collapse violently as the pressure recovers downstream of the restriction: the vapor bubble collapse generates localized pressure spikes of thousands of psi concentrated on a microscopic scale at the point of collapse, which over thousands of cycles of bubble formation and collapse erodes the metal surface of the valve seat and trim through a process called cavitation erosion, producing a pitted, rough, sponge-like surface finish that progressively worsens until the valve requires replacement; anti-cavitation valve trim designs (including multi-stage pressure reduction, labyrinthine flow paths, and enhanced-clearance ball trim) distribute the pressure drop across multiple stages rather than dropping the full pressure difference across a single orifice, preventing the local pressure at any single stage from falling below the vapor pressure and eliminating the bubble formation that initiates cavitation; the service severity of cavitation in oil field control valves is quantified by the cavitation index (sigma, the ratio of the net positive pressure at the valve outlet above the vapor pressure divided by the total pressure drop across the valve), with sigma values below approximately 0.5 indicating high cavitation risk that requires anti-cavitation trim selection.
• Flash gas recovery from LPG and unstabilized condensate handling systems captures the hydrocarbon vapor released when the high-pressure liquids are transferred to storage tanks or loading facilities at lower pressure, using a vapor recovery unit (VRU) or flash gas compressor to compress the low-pressure flash gas to sales or fuel gas pressure rather than venting or flaring it: when LPG (propane, butane, or a mixture) is transferred from a pressurized rail car or tank truck to a lower-pressure storage sphere or bullet tank, the pressure reduction causes a fraction of the LPG to flash to vapor (the fraction determined by the vapor-liquid equilibrium at the new pressure and the LPG composition); capturing this flash vapor prevents both the economic loss of saleable LPG and the environmental and safety hazard of venting or flaring the gas; the flash gas compressor takes suction from the vapor space of the receiving vessel, compresses the flash gas to the higher pressure of the supply system, and returns it to the liquid phase for recovery or sale; in production operations, wellhead and separator flash gas from high-GOR reservoirs represents a significant fraction of the total gas production that must be captured and compressed to sales pressure, with flash gas compressors at wellsites being a common installation in high-shrinkage gas condensate fields where the difference in GOR between reservoir and surface conditions produces large volumes of flash gas at the separators.
• Internal flash in heat exchangers causes two-phase flow on the process side that can dramatically reduce heat transfer efficiency compared to the design single-phase condition, because the transition from liquid to two-phase vapor-liquid occurs partway through the exchanger and changes the local heat transfer coefficient from the single-phase liquid value to the two-phase value (which is often lower on the sensible heat transfer side but higher on the boiling side, depending on the flow regime): in a feed-effluent heat exchanger for an amine gas treating plant, if the lean amine is throttled into the exchanger at a pressure below the solvent's bubble point (at which CO2 and other dissolved gases begin to flash from solution), the resulting two-phase flow through the tube bundle reduces the lean amine side heat transfer coefficient and can cause flow distribution problems in multi-pass arrangements where some passes receive predominantly liquid and others receive predominantly vapor; managing internal flash in heat exchangers requires either maintaining the inlet pressure above the bubble point by controlling the upstream pressure or by using a back-pressure regulator on the exchanger outlet, or designing the exchanger for two-phase flow conditions that accommodate the flash and maintain adequate heat transfer coefficient throughout the two-phase region; in natural gas processing cryogenic heat exchangers (cold boxes), controlled internal flash is an essential part of the process design where the natural gas stream is intentionally cooled below the dew point to condense NGL components, with the two-phase flow design being integral to the heat exchanger selection and pressure drop calculation.
• Internal flash in subsea pipelines and risers presents specific flow assurance challenges because the gas that flashes from the oil as pressure drops along the pipeline and up the riser can accumulate in high spots in the pipeline geometry (slug traps) or travel as a slug flow pattern that delivers alternating large gas bubbles and liquid slugs to the surface separator in an intermittent, pulsating manner that exceeds the separator's design capacity for liquid surge: the flow assurance analysis of a deepwater production system models the two-phase flow behavior from the wellhead through the flowline, riser, and topsides facilities to determine whether the internal flash and resulting slug flow behavior is within the separator's design envelope or whether slug catchers, topside choke valves, or flow control strategies are needed to manage the slug flow; severe slugging (a particularly harmful form of slug flow that occurs in systems with a flowline that dips before rising in the riser, causing intermittent backflow and accumulation of liquid in the flowline dip followed by explosive purging of the liquid slug up the riser) can exceed the separator's liquid handling capacity by 5 to 10 times the average flow rate, requiring either designing the separator for the peak slug volume or implementing flow control to suppress severe slugging; subsea processing (subsea separators and multiphase boosting systems) provides one approach to managing the internal flash problem by separating gas and liquid subsea before the mixture enters the riser, eliminating the two-phase riser flow and its associated slug flow problems.