Spinner Flowmeter: Definition, Types, and PLT Interpretation

What Is a Spinner Flowmeter?

A spinner flowmeter is a downhole production logging tool that measures in-situ fluid velocity inside a wellbore by counting the rotational speed of an impeller or vane assembly. As wellbore fluid flows past the spinner, it imparts a rotational force proportional to velocity, generating electrical pulses that surface acquisition systems convert into flow rate profiles across producing or injecting intervals.

How a Spinner Flowmeter Works

The operating principle of a spinner flowmeter is straightforward: when fluid moves past an impeller mounted in the wellbore fluid stream, the fluid exerts a drag force on the impeller blades that causes them to rotate. The rotational speed of the impeller (measured in revolutions per second, RPS) increases with fluid velocity and decreases as fluid velocity drops toward zero. An electrical pickup coil or Hall-effect sensor mounted adjacent to the impeller shaft generates a pulse for each complete revolution; surface acquisition systems count these pulses over a fixed time gate to compute instantaneous RPS as the tool traverses the well. The relationship between RPS and the fluid velocity relative to the tool (the apparent velocity) is linear across most of the tool's operating range, allowing the calibration equation RPS = a x V_rel + b to be applied, where V_rel is the relative velocity between the fluid and the tool, and a and b are calibration constants determined on a surface flow loop prior to logging.

Because the tool itself moves through the wellbore at a controlled logging speed set by the surface winch, the measured RPS reflects the sum of the formation fluid velocity and the tool velocity. To extract the true formation flow velocity, the engineer must correct for tool motion. When the tool moves upward (against production flow in a producing well), the relative velocity between fluid and tool is the fluid velocity plus the tool speed; when the tool moves downward, the relative velocity is the fluid velocity minus the tool speed. By running the tool at multiple speeds in both directions, the engineer can construct a plot of apparent RPS versus tool velocity at any depth and identify the zero-crossing, which corresponds to the fluid velocity at that depth. The volumetric flow rate at each depth is then calculated from the derived velocity using the wellbore cross-sectional area, corrected for any slippage between phases and for spinner bypass (the fraction of wellbore flow that passes around the tool without spinning the impeller). Differential flow rate between depth stations directly identifies the contribution of each producing or injecting interval.

The minimum detectable velocity, or threshold velocity, is the lowest fluid velocity that can overcome the mechanical friction of the impeller bearings and cause measurable rotation. For a typical small-vane through-tubing spinner, the threshold is approximately 0.05 to 0.15 m/s (0.16 to 0.49 ft/s). Fullbore spinners have lower thresholds because the larger impeller area generates more torque per unit velocity. Below threshold, the spinner reads zero even though flow may be present, creating a blind zone for low-rate intervals. In low-rate or injection wells where velocities approach the threshold, engineers may use the packer or basket flowmeter to divert all wellbore flow through a smaller cross-section past the impeller, dramatically increasing the fluid velocity relative to the spinner and extending the measurable range to much lower in-situ flow rates.

Spinner Flowmeter Types

Continuous (Through-Tubing) Spinner

The continuous spinner is the most commonly deployed configuration. It consists of a small-diameter (typically 1.25 to 1.75 in. / 31.8 to 44.5 mm OD) body that runs inside the production tubing on wireline or coiled tubing, carrying a 1.25 to 1.5 in. (31.8 to 38.1 mm) diameter impeller centrally positioned in the fluid stream. Because the tool OD is small relative to the tubing ID, a significant fraction of the total flow passes in the annulus between the tool body and the tubing wall without interacting with the spinner. The bypass correction factor, typically 0.5 to 0.8 depending on tool OD and tubing ID, must be applied to convert measured flow at the spinner to total wellbore flow. The continuous spinner is most effective in single-phase or predominantly single-phase wells at moderate to high flow rates. Its small size allows deployment through a lubricator without killing the well, making it the preferred tool for routine production surveillance.

Fullbore Spinner

The fullbore spinner uses a large-diameter impeller mounted on centralizer arms that position it at the center of the tubing or casing bore, with the impeller diameter close to the bore ID. By minimizing the bypass annulus, the fullbore spinner captures nearly all of the wellbore flow and requires only a small bypass correction. Fullbore spinners are significantly more sensitive at low flow rates than continuous spinners and are the preferred tool for wells with low flow rates, gas wells, or wells where accurate zone allocation at low rates is critical. The larger tool diameter means it cannot pass through tubing restrictions, so fullbore spinners are most commonly used on open-hole or cased-hole logging strings where the full wellbore is accessible, or in tubing-pulled configurations. Centralizer arms collapse mechanically for running through tight spots and open against the wellbore wall at logging depth.

Packer (Diverter) Flowmeter

The packer flowmeter, sometimes called the diverter flowmeter, incorporates an inflatable or mechanical packer element that seals against the tubing or casing wall above the spinner, forcing all wellbore fluid to flow through the spinner body rather than around it. Because 100% of the flow passes through the spinner, there is no bypass correction. The packer flowmeter has the lowest threshold velocity of all spinner types and can resolve flow rates below 5 m3/d (approximately 31 bbl/d) that a continuous spinner would not detect. Its limitation is that the packer must be inflated at each measurement station and then deflated and moved, making the logging process slow and expensive relative to a continuous spinner run. Packer flowmeters are primarily used for detailed zone-by-zone allocation studies on complex multi-layer wells, for injection profiling in waterflood or steamflood projects, and in very-low-rate wells where standard spinner sensitivity is insufficient.

Basket Flowmeter

The basket flowmeter uses a funnel-shaped deflector basket that is opened mechanically in the wellbore to intercept a portion of the flow stream and direct it past the spinner. Unlike the packer flowmeter, the basket does not seal completely against the wellbore wall, so some bypass still occurs, but the deflector increases the fraction of total flow passing the spinner relative to a continuous spinner. Basket flowmeters are positioned at stationary stations in the same manner as packer flowmeters and are well-suited for moderate-to-low rate wells where packer inflation and sealing may be mechanically challenging (e.g., in corroded or scaled-up tubulars). The basket deflector also helps in multiphase wells where gas segregation can cause a centralized spinner to read predominantly gas velocity rather than the average mixture velocity.

Production Logging Tool String Configuration

The spinner flowmeter is rarely run alone. A complete production logging string combines the spinner with a suite of sensors that characterize both the quantity and composition of fluids flowing at each depth. The standard combined PLT string for a vertical oil well includes a gamma ray tool (for depth correlation with the open-hole log), a casing collar locator (CCL), a pressure gauge (quartz crystal or strain gauge), a thermometer, a gradiomanometer or fluid density tool, a capacitance or optical water holdup probe, and the spinner. In some configurations, especially in gas-lifted or gassy wells, a caliper tool is added to measure actual tubing or casing ID for accurate velocity-to-flow-rate conversion.

The pressure and temperature sensors enable construction of a flowing gradient survey across all producing intervals, which independently confirms the spinner-derived flow profile through hydrostatic pressure calculations. If the flowing gradient shows a change in fluid gradient (e.g., a transition from oil to water in the hydrostatic column) at the same depth as a spinner anomaly, the two measurements reinforce the zone identification. The fluid density sensor measures the bulk density of the mixed fluid stream and, when combined with individual fluid densities for oil, water, and gas determined at surface conditions, allows calculation of in-situ holdup fractions (the fraction of the wellbore cross-section occupied by each phase) at each depth. The holdup measurement is essential for converting mixture velocity from the spinner to individual phase velocities, which in turn allow the total flow rate to be decomposed into separate oil, water, and gas contributions from each zone.

Interpretation of a combined PLT string in a multiphase flowing well requires knowledge of the slip model: the relationship between the velocities of the different phases relative to each other and to the mixture. In vertical wells, gas rises faster than liquid (positive slip), water falls faster than oil (negative slip relative to oil), and the mixture velocity measured by the spinner reflects a weighted combination. The Gradiomanometer-Spinner method uses the measured fluid density gradient from the density tool and the spinner velocity to solve simultaneously for oil, water, and gas holdups and flow rates, using established multiphase flow correlations. In practice, this system of equations is underdetermined without additional sensors, which is why the full PLT string with multiple independent measurements provides substantially better accuracy than a spinner alone.