Torque Flowmeter

Key Takeaways

• The basket spinner PLT tool is the most widely used torque-type flow measurement instrument in petroleum well surveillance, designed to quantify the flow contribution of individual producing zones in a commingled completion or to identify zones that are not contributing or are accepting injection: the basket spinner consists of 4-8 curved plastic or metal vanes arranged around a central shaft, rotating freely in response to fluid flowing past the tool during a logging pass; in a producing well, the fluid flows upward past the tool, rotating the spinner at a rate proportional to the local upward fluid velocity; the logging truck moves the tool upward and downward through the producing interval at controlled speeds, and the spinner RPM is recorded continuously as a function of depth; the net spinner speed (the difference between spinner RPM when the tool moves upward against the fluid flow and when the tool moves downward with the fluid flow) is used to compute the true fluid velocity at each depth, correcting for the tool's own movement through the fluid; above the top perforations, the total well flow passes the tool and produces the highest spinner speed; as the tool passes each perforated interval moving downward from the top, the spinner speed decreases by an amount proportional to the flow contribution of the interval that was crossed; integrating these spinner speed decrements across each perforated zone gives the flow profile — the fraction of total well production attributable to each zone — which is the primary deliverable of a production logging run.
• Multiphase flow complications affect the accuracy of spinner PLT measurements in wells producing oil, water, and gas simultaneously, because the different phases have different densities and viscosities and tend to segregate or slip relative to each other in the wellbore, causing the local fluid velocity measured by the spinner to differ from the mean cross-sectional fluid velocity needed to compute the volumetric flow rate: in a wellbore with significant gas fraction, gas bubbles rise faster than the liquid phase (gas-liquid slip velocity of 0.3-0.5 m/s for free gas in a vertical wellbore), so the local fluid velocity measured by the spinner at any point in the annulus reflects a weighted average of the gas and liquid velocities rather than the mean volumetric velocity; the spinner calibration (the relationship between spinner RPM and fluid velocity) is typically established in a single-phase test fluid and may not be accurate in the multiphase wellbore environment; spinner anomalies in multiphase flow (spinner speed higher than expected for the total flow rate, or spinner direction reversal in sections of the wellbore where gas rises faster than liquid falls) require careful interpretation using additional PLT sensors (fluid density from a gradiomanometer, holdup from a capacitance or conductivity sensor, and temperature from a temperature log) to separate the contributions of each phase and compute the phase-specific flow rates; the full PLT interpretation in a multiphase producer using all available sensors to compute oil, water, and gas flow profiles is considerably more complex than the single-phase spinner interpretation and requires specialized software and expertise.
• Continuous versus stationary spinner measurements provide complementary information about well flow behavior: continuous spinner logs (the standard PLT acquisition mode where the tool moves continuously through the wellbore while recording spinner RPM as a function of depth) provide a complete flow profile in a single logging pass but may miss short-duration flow events (intermittent gas slugs, periodic backflow from a thief zone) that occur between tool passes; stationary spinner measurements (stopping the tool at a fixed depth and recording spinner speed as a function of time for several minutes) provide a time-series record of flow variability at that depth, detecting periodic slug flow, wellbore pressure oscillations, and other dynamic phenomena that are invisible to the continuous log; in wells with known or suspected slug flow (common in gas lift wells, wells with liquid loading, or horizontal producers where hydrodynamic instabilities cause intermittent gas and liquid slugs to pass the tool), stationary measurements at multiple depths provide a more complete understanding of the flow regime than continuous logging alone; PLT data quality is also affected by centralizer placement — a well-centralized spinner tool that rotates in the center of the wellbore measures the average radial velocity profile more accurately than an eccentered tool that is pushed to one side of the wellbore and samples only the flow velocity near the borehole wall.
• Injection profiling using spinner PLT tools in water or gas injection wells applies the same measurement principle in reverse: injection fluid flows downward past the logging tool from the wellhead to the perforations, and the spinner tool records the downward flow velocity profile to determine how the total injection rate is distributed among the perforated intervals; zones with higher permeability or lower reservoir pressure receive more injection than tight or high-pressure zones, and the injection profile from a spinner PLT quantifies this distribution; the diagnosis of injection conformance (whether the injection is being delivered uniformly to all zones as designed, or concentrated in a few high-permeability thief zones at the expense of the intended target zones) guides remedial actions such as selective plugging of thief zones with gel or cement, reperforating target zones to improve injectivity, and adjusting injection wellhead pressure to redistribute the injection profile; in water flood management, repeated injection PLT runs (annually or after injection rate changes) track the evolution of the injection profile over time, monitoring whether gel treatments or matrix acidizing of target zones has achieved the intended improvement in conformance; the injection PLT spinner speed profile is often combined with temperature logs (which show warming below the top injection perforation where cool injection water flows downward, and cooling or anomalies at individual injection layers where water enters the formation) to provide a more complete picture of injection distribution.
• Horizontal well PLT using spinner tools presents specific challenges because the fluid flow in horizontal wells is gravity-segregated (gas rises to the top of the wellbore, water settles to the bottom, oil occupies the middle) and the tool must be mechanically conveyed through the horizontal section using coiled tubing or tractor rather than simply being pulled upward by the wireline: the gravity segregation of fluids in horizontal wellbore means that a central spinner tool measures the velocity of the phase that occupies the center of the pipe (typically oil or water-oil mixture), not the velocity of the heavy or light phase that may be segregated to the bottom or top; multi-sensor PLT tools for horizontal wells include multiple sensors positioned at different radial locations in the wellbore cross-section (array spinner tools, or tools with both top and bottom sensors) to capture the velocity of each phase separately; the interpretation of horizontal well PLT data to compute oil, water, and gas flow contributions from individual fracture stages or reservoir layers requires modeling the stratified or annular flow regime rather than the slug or dispersed bubble flow models applicable to vertical wells; despite these complications, horizontal well PLT is an important diagnostic tool in unconventional completions where understanding the contribution of individual hydraulic fracture stages to total well production is critical for optimizing future completion designs and for identifying underperforming stages that may be candidates for refracturing.