churn flow

Churn flow in petroleum production engineering is a chaotic, highly turbulent multiphase flow regime that occurs in vertical and near-vertical wellbores and pipelines when the gas-liquid ratio is high enough to cause intermittent slug flow to break down into a disordered oscillating pattern characterized by large gas structures with highly distorted, churning liquid films and frequent direction reversals of the liquid phase, representing the transition regime between slug flow (lower gas velocity) and annular-mist flow (higher gas velocity) in the Duns and Ros, Griffith-Wallis, and Beggs-Brill vertical multiphase flow correlations used in WCSB production engineering; in Western Canada Sedimentary Basin oil and gas production, churn flow is most commonly encountered in the tubing strings of WCSB high-GOR Devonian and Montney gas condensate wells, in gas-lifted WCSB Cardium and Viking oil wells where the injected gas breaks the liquid column into a chaotic multiphase mixture, and in the riser sections of WCSB steam-assisted gravity drainage (SAGD) wellpairs at Cold Lake and Christina Lake where the steam-water-bitumen mixture in the production tubing transitions through slug and churn flow regimes as pressure and temperature decrease from the reservoir to surface. The transition from slug flow to churn flow in WCSB vertical tubing occurs when the superficial gas velocity (Vsg) in the tubing exceeds approximately 1 to 3 m/s for typical WCSB gas-oil mixtures at 10 to 25 MPa wellhead pressure and 50 to 150 degrees Celsius, depending on tubing diameter (5.5-inch or 7-inch production tubing) and the liquid holdup fraction; at this transition, slug bubbles elongate and become unstable, their noses oscillating downward before rising again in a churning motion that creates a highly heterogeneous liquid distribution with instantaneous liquid velocities locally downward (falling liquid film on the tubing wall) and upward (entrained droplets in the gas core), making churn flow one of the most difficult regimes to model accurately with empirical correlations or mechanistic models in WCSB nodal analysis calculations. The practical consequence of churn flow in WCSB production tubing is that the pressure gradient calculation using multiphase flow correlations has the highest uncertainty of all flow regimes (prediction error of 20 to 40 percent versus 5 to 15 percent in bubble flow or annular flow), leading to errors in tubing performance curve construction that can cause suboptimal choke or gas lift valve setting in WCSB gas condensate and gas-lifted oil production optimization programs.

• Churn flow regime identification and transition criteria in WCSB vertical wellbore multiphase flow: The onset of churn flow in WCSB vertical production tubing is predicted by multiphase flow maps (Duns and Ros map using dimensionless liquid and gas velocity numbers, Griffith-Wallis map using mixture velocity and void fraction) that define transition boundaries between bubble flow, slug flow, churn flow, and annular-mist flow as functions of superficial gas and liquid velocities. For a WCSB Devonian gas condensate well producing 100,000 m3/d of gas and 15 m3/d of condensate through 73 mm OD production tubing (57 mm ID) at 12 MPa wellhead pressure, superficial gas velocity is approximately 2.8 m/s and superficial liquid velocity is 0.04 m/s; positioning these values on the Duns and Ros flow map places the flow well within the churn flow transition zone between slug and annular flow. Mechanistic models (Ansari, Hasan-Kabir) predict the slug-to-churn transition when the Taylor bubble rise velocity equals the net liquid velocity (flooding condition), which in WCSB 73 mm tubing at 10 MPa occurs at gas superficial velocities of 1.5 to 2.5 m/s depending on fluid properties; these models are used in WCSB well performance software (Prosper, Pipesim) to automatically identify the flow regime at each pressure-temperature node along the wellbore and apply the appropriate pressure gradient correlation.
• Pressure gradient uncertainty in churn flow and WCSB nodal analysis implications: The pressure gradient in churn flow has three components (static head, friction, and acceleration), but the static head component (dominated by liquid holdup) is the most uncertain because churn flow liquid holdup fluctuates rapidly between 0.1 and 0.8 (10 to 80 percent liquid by volume at any instant) as gas surges and liquid falls back, making time-averaged holdup difficult to predict without empirical calibration to local WCSB well data. The Beggs-Brill correlation (widely used in WCSB production engineering software) predicts churn flow pressure gradients with mean absolute error of 25 to 35 percent in vertical tubing, compared to 8 to 12 percent for bubble flow; this uncertainty propagates into WCSB tubing performance curves (TPC), shifting the intersection of the TPC with the inflow performance relationship (IPR) by 5 to 15 percent in flow rate, equivalent to 500 to 2,000 m3/d uncertainty in predicted stabilized rate for a WCSB Montney gas well producing 10,000 to 20,000 m3/d. WCSB operators conducting production optimization on Devonian gas condensate fields use measured flowing gradient surveys (spinner surveys or distributed temperature sensing) to calibrate the multiphase flow model to actual wellbore conditions, reducing the churn flow pressure gradient uncertainty from 30 percent to 10 to 15 percent after calibration to one to three WCSB reference wells in the field.
• Churn flow in WCSB SAGD production tubing and steam-bitumen-water multiphase transport: In WCSB SAGD wellpairs at Cold Lake, Christina Lake, and Surmont, the production tubing carries a complex three-phase mixture of subcooled liquid water, steam vapor, and emulsified bitumen from the horizontal producer to surface; this three-phase mixture passes through slug and churn flow regimes in the build section and vertical portion of the production tubing as the mixture pressure decreases from 2 to 4 MPa at the pump intake to 0.5 to 1.5 MPa at the surface wellhead. Electric submersible pumps (ESPs) installed in WCSB SAGD producers at depths of 300 to 500 m in the build section experience severe vibration and motor instability when operating in churn flow, because the chaotic liquid-gas distribution in the suction intake causes gas locking (gas fills the pump stages rather than liquid) at gas void fractions above 0.15 to 0.25, reducing pump efficiency from 60 to 75 percent (full liquid) to below 20 to 30 percent (gas-cut pump). Progressing cavity pumps (PCPs) used in some WCSB SAGD producers are less sensitive to churn flow gas entrainment than ESPs because the PCP's positive displacement action handles gas-liquid mixtures up to 50 to 60 percent gas void fraction before gas slugging causes stator damage, allowing WCSB SAGD producers to operate through the churn flow regime without flow-induced pump failure.
• Gas lift design for WCSB oil wells and churn flow avoidance in unloading valve sequencing: Gas lift completion design for WCSB Cardium and Viking oil wells uses a series of mandrels with gas lift valves (GLVs) spaced at 200 to 500 m intervals in the production tubing; during unloading (the process of lifting kill fluid out of the tubing after completion or workover), each GLV must lift the fluid column above it to surface before the next lower GLV is opened. If gas injection rate is too high during unloading, the gas-liquid mixture above the active GLV transitions from slug flow to churn flow prematurely, reducing liquid transport efficiency (churn flow liquid velocity is 30 to 50 percent lower than optimum slug flow liquid velocity) and causing liquid fallback through the active GLV that blocks unloading progression. WCSB gas lift unloading procedures specify maximum gas injection rates (calculated to maintain superficial gas velocity below the slug-to-churn transition velocity at each unloading stage) and minimum tubing pressure differentials across each GLV to ensure slug flow is maintained throughout unloading; Petrolia, Trican, and STEP Energy Services gas lift field engineers monitor wellhead casing and tubing pressures during WCSB Cardium unloading to identify churn flow onset by the characteristic pressure oscillations (0.2 to 1.0 MPa amplitude, 0.1 to 0.5 Hz frequency) that distinguish churn flow from stable slug flow.
• Churn flow liquid fallback and its impact on WCSB gas well liquid loading: Liquid loading in WCSB gas wells occurs when gas velocity in the tubing drops below the critical velocity required to continuously lift liquid droplets (Turner critical velocity, approximately 3 to 8 m/s for WCSB gas condensate wells with 73 mm tubing at 5 to 15 MPa wellhead pressure), causing liquid accumulation in the wellbore that increases backpressure and reduces gas production rate. The churn flow regime is directly involved in the incipient liquid loading process: as gas rate declines toward the Turner critical velocity, annular-mist flow transitions to churn flow, and the churning liquid films begin falling back intermittently; this churn flow liquid fallback is the precursor to slug flow and eventually full liquid loading where the gas rate drops catastrophically. WCSB Devonian and Montney gas wells exhibiting early liquid loading symptoms (erratic wellhead pressure, intermittent liquid slugs at surface separators, declining stabilized rate below IPR prediction) are typically in the churn flow to slug flow transition; WCSB operators install plunger lift systems or velocity strings (smaller diameter tubing that increases gas velocity back into the annular-mist regime) to restore continuous liquid lift and prevent progression to full liquid loading requiring costly well kill and workover.

Churn Flow Liquid Loading Diagnosis and Plunger Lift Installation in WCSB Devonian Gas Well

A WCSB Devonian Wabamun gas well producing 35,000 m3/d through 73 mm OD tubing at 7.2 MPa wellhead pressure began exhibiting erratic wellhead pressure fluctuations (0.3 to 0.8 MPa oscillation at 0.2 Hz) and intermittent liquid slugs at the separator after 8 years of production. Nodal analysis confirmed the well was in the churn flow regime: Vsg = 1.6 m/s (below the 2.2 m/s annular-mist transition). Pressure gradient survey showed 14 percent higher pressure gradient than the Beggs-Brill prediction, consistent with churn flow liquid holdup above model prediction. A plunger lift system was installed with a 48 mm plunger on a standing valve at 1,850 m depth; plunger cycling at 4 cycles per day with 45-minute flow and 15-minute shut-in intervals swept accumulated liquid from the tubing on each cycle, restoring the well to 28,000 m3/d stabilized production (previously declining from a pre-loading rate of 42,000 m3/d). Wellhead pressure oscillations ceased after plunger installation; the well remained on plunger lift for 6 years until reservoir pressure declined below minimum plunger operating pressure.

Related Terms

Multiphase flow encompasses all simultaneous gas-liquid flow regimes in WCSB production tubing and pipelines; churn flow is the most difficult regime to model accurately, with 25-35% pressure gradient prediction error in standard WCSB nodal analysis correlations. Slug flow is the adjacent lower-gas-velocity regime that transitions to churn flow as Vsg exceeds 1-3 m/s in WCSB vertical tubing; slug flow provides more efficient liquid lift than churn flow and is the target operating regime for WCSB gas-lifted oil wells. Liquid loading in WCSB gas wells begins with churn flow liquid fallback as gas velocity declines below Turner critical velocity; early intervention with plunger lift or velocity strings in the churn flow stage prevents progression to full liquid loading requiring a well kill. Nodal analysis in WCSB production optimization uses multiphase flow correlations to predict tubing performance curves; churn flow uncertainty of 25-35% must be calibrated against measured flowing gradient surveys to improve rate prediction accuracy. Plunger lift manages churn flow liquid accumulation in WCSB Devonian and Montney gas wells; the plunger sweeps accumulated liquid on each cycle, restoring gas velocity to the annular-mist regime and preventing progressive liquid loading.