Fullbore Spinner
A fullbore spinner is a production logging tool that measures fluid flow velocity inside a wellbore using a multi-blade impeller (spinner) that rotates at a speed proportional to the fluid velocity past the tool — the fullbore design uses a large-diameter impeller that spans most of the casing inner diameter so the spinner samples the bulk wellbore fluid velocity rather than the near-wall velocity, providing a representative average flow velocity measurement across the pipe cross-section that is used to calculate volumetric flow rates of oil, gas, and water individually when combined with fluid density and holdup measurements from accompanying spinner-suite sensors.
Key Takeaways
- Fullbore spinner response depends on fluid velocity relative to the tool's own motion — when run in continuous or station mode, the spinner RPS (revolutions per second) is converted to fluid velocity using a calibration equation: V_fluid = (RPS - RPS_threshold) / K + V_tool, where RPS_threshold is the threshold speed below which friction prevents rotation (typically 0.5 to 1.5 RPS), K is the spinner constant (RPS per unit velocity, determined by calibration in known flow conditions), and V_tool is the tool velocity in cable depth mode; the threshold and K values are tool-specific and change with fluid type (water versus oil versus gas bubbles contacting the spinner blades), requiring separate calibration passes at multiple cable speeds to resolve the spinner equation accurately in multi-phase flow environments.
- Production allocation from spinner logs requires running the spinner at multiple tool velocities in the wellbore (typically 3 to 5 passes up and down at different cable speeds) to generate a spinner response vs. tool velocity dataset from which the fluid velocity and flow contributions from individual perforated intervals can be extracted by differentiation — the difference in total flow rate between adjacent perforated zones, computed from the velocity-to-flow-rate conversion at each depth, gives the individual zone contribution to total production; this differential flow rate analysis identifies which perforations are flowing, which are taking fluid (cross-flow under shut-in), and which are inactive, enabling production optimization decisions about which intervals to shut off or stimulate.
- Fullbore versus tubing spinners reflect the two main deployment geometries for downhole flow meters — fullbore spinners are designed for cased-hole production logging in the casing annulus or liner where the large impeller fits the casing ID and samples the full cross-section; tubing spinners are smaller-diameter tools designed to be run through production tubing on wireline, measuring only the flow through the tubing string; a downhole measurement string may combine a fullbore spinner in the casing with a gradiomanometer (pressure gradient tool for fluid density), a capacitance or gamma-gamma holdup sensor (water fraction), and a temperature log to provide a complete production profile that separates oil, water, and gas contributions at each producing interval.
- Spinner threshold effects in low-velocity flow cause the most common interpretation error in production logging — when wellbore fluid velocity is below the spinner threshold (typically at shut-in or very low rate), the spinner reads zero and cannot distinguish between zero flow and very low flow; cross-flow between perforated intervals under shut-in conditions (where formation pressure differentials drive fluid from high-pressure to low-pressure zones within the wellbore) produces velocities below the spinner threshold and goes undetected if only spinner data is used; temperature logs and fluid density logs that change character across cross-flowing intervals provide complementary evidence for low-velocity flow that the spinner misses, making temperature logging an essential companion to spinner surveys in wells suspected of wellbore cross-flow.
- Gas-liquid flow complicates spinner interpretation because gas bubbles traveling up the annulus at different velocities than liquid create a slip velocity between phases that makes the spinner velocity difficult to convert to individual phase volumetric rates without a phase holdup measurement — the slip model used in multiphase flow interpretation accounts for the fact that gas rises faster than liquid in vertical or deviated flow, and that the spinner measures a mixture velocity that is neither the gas velocity nor the liquid velocity; combining the fullbore spinner velocity with a gamma-gamma density tool (which measures average mixture density) and a capacitance or microwave holdometer (which measures water hold-up fraction) provides the three independent measurements needed to solve for three-phase (oil, water, gas) flow rates using a slip-corrected multiphase flow model.
Fast Facts
The spinner flowmeter was introduced to the oil industry in the 1950s as a simple mechanical flow indicator, with the first quantitative production logging using spinner surveys in combination with temperature logs developing through the 1960s. The modern fullbore production logging string — combining a large-diameter spinner, fluid density tool, water holdup measurement, and temperature/casing collar locator — became a standard production logging service offered by Schlumberger, Halliburton, and Baker Hughes from the 1970s onward and remains the primary tool for production profiling in cased-hole wells today. Modern high-resolution production logging tools (Schlumberger's FloView and GHOST tools, Halliburton's Phase Velocity Log) add individual phase velocity measurements using capacitance and inductance sensors to improve three-phase flow rate resolution beyond what the spinner-plus-holdup combination alone can provide in complex deviated or horizontal well geometries.
What Is a Fullbore Spinner?
When a production well produces from multiple perforated intervals, the natural question is: which intervals are actually contributing and in what proportions? The total surface production rate tells you nothing about which zones are working hardest and which are effectively dead. A wellbore flow profile obtained from a production logging run with a fullbore spinner answers that question by measuring how fast fluid flows past the tool at every depth, allowing the flow rate entering the wellbore from each perforation interval to be calculated by difference.
The physics is straightforward: fluid flowing upward past the spinner blades rotates the impeller. Faster fluid means faster rotation. By running the tool at several different cable speeds and measuring the spinner RPM at each speed, the calibration equation can be solved to extract the true fluid velocity at every depth. Integrating velocity over the pipe cross-section (knowing the casing inner diameter) gives volumetric flow rate. The flow rate entering between any two depth intervals is the difference in flow rates above and below that interval.
The practical complexity arises from multiphase flow — oil, water, and gas each flow at different velocities in the wellbore, and the spinner measures a mixture velocity that depends on which phases are present and at what fractions. Modern production logging strings address this by combining the fullbore spinner with additional sensors that measure fluid density and water fraction, providing enough information to apply a multiphase flow model and estimate individual phase rates at each depth interval.
Fullbore Spinner Operations and Interpretation
Production logging survey design specifies the number of passes, tool speeds, and flow rate conditions needed to generate reliable spinner data — a standard production logging run in a cased-hole producer includes at least three upward passes at different cable speeds (typically 20, 40, and 60 feet per minute) and three downward passes at matching speeds, run both during production at the surface and under shut-in conditions if cross-flow is suspected; the shut-in survey is particularly valuable because cross-flow under static conditions identifies intervals with pressure support (flowing into the wellbore) and intervals with drainage (taking fluid from the wellbore), a distinction that the under-flowing survey cannot detect because all zones show upward flow during production; the pair of flowing and shut-in surveys together is the most informative production logging dataset for diagnosing wellbore fluid distribution and formation pressure support.
Depth correlation between spinner passes and perforations requires a casing collar locator (CCL) that tags each collar joint as the tool passes through it — the CCL signal provides a depth reference that correlates every spinner reading to the specific perforation interval it is reporting on, since the perforations are at known depths relative to the collar log; without CCL depth correlation, spinner readings cannot be reliably assigned to individual perforated zones in wells with closely spaced perforations or in wells where pipe movement under pressure has shifted depths from the original completion record.
Fullbore Spinner Across International Jurisdictions
Canada (AER / WCSB): WCSB production logging with fullbore spinners is standard practice in multi-zone Montney, Cardium, and Mannville completions where identifying which hydraulically fractured stages are contributing production helps optimize refracturing and zone-selective workover decisions; AER production reporting requirements use surface measurement as the basis for regulatory reporting, but fullbore spinner production profiles provide the engineering data for well performance diagnostics and for characterizing reservoir performance in the pool-level production surveillance that supports AER's reserves assessment process. Alberta's extensive vertical multi-zone well inventory makes production logging with spinner surveys a routine diagnostic tool for identifying zone deterioration and cross-flow behind casing.
United States (API / BSEE): GoM deepwater production logging with fullbore spinners in subsea wells presents significant operational challenges because of the time and cost required to pull the production tubing or run the tool on slickline through a tree-mounted lubricator system against high wellbore pressure; as a result, deepwater production profiling increasingly uses permanent downhole gauge arrays and fiber optic distributed temperature sensing (DTS) systems as alternatives to periodic wireline spinner surveys, though spinner surveys remain the definitive measurement when individual zone contributions need to be quantified for well performance audits and production allocation in co-mingled completion strings; BSEE requires production allocation documentation for GoM multi-zone completions, with spinner surveys accepted as engineering support for zone-by-zone production attribution.
Norway (Sodir / NORSOK): NCS production logging programs use fullbore spinners and comprehensive production logging strings (PLT) in horizontal and high-angle wells in North Sea fields including Statfjord, Oseberg, and Gullfaks to identify water breakthrough front positions and adjust water injection profiles accordingly; Sodir's requirement for production performance reporting for each NCS license block drives the use of production logging to support well and reservoir performance evaluations submitted in annual field development plan updates; Norwegian research at IFE and SINTEF has contributed to multiphase flow model development for PLT interpretation in horizontal well geometries where conventional spinner interpretation methods developed for vertical wells give inaccurate results due to phase segregation effects.
Middle East (Saudi Aramco): Saudi Aramco deploys fullbore production logging strings extensively in Arab Formation horizontal producers and vertical multi-zone completions to monitor waterfront advancement from the active Ghawar waterflood program; spinner surveys identify the arrival of injection water at each producing perforation interval by the change in spinner-measured flow rate that accompanies the increase in total fluid rate as the higher-mobility water replaces oil in the near-wellbore region; Aramco uses production logging data to drive real-time adjustments to injection well patterns, shutting off perforations in producers where the WOR has risen beyond economic limits while maintaining production from zones still within acceptable water cut range; this detailed production profiling program is what allows Ghawar to maintain high oil production rates despite decades of waterflood operation.