SPINNER FLOWMETER BASICS
Flowmeters use an impeller (spinner) driven by the movement of borehole fluid. The data is recorded as revolutions per second (rps)  which, when properly calibrated, leads to the velocity of fluids in the tubing or casing in a production or injection well. Knowing the pipe size, we can calculate flow rate in barrels per day (bopd or bwpd). A few other details are needed to handle gas rates.

On a fullbore flowmeter, the spinner assembly folds into a diameter small enough to fit into the tubing, and expands to a larger diameter for surveys in the casing below the tubing.

Continuous flowmeters do not fold and are best suited for surveys in the tubing.

Both continuous and fullbore flowmeters can be logged downward and upward to create continuous logs. Logging in both directions at several different logging speeds is a normal procedure to determine friction effects on the spinner, giving a method for downhole calibration.

<== Diverting or basket flowmeter

Diverting flowmeters are the most accurate of the spinner devices in low rate and multi-phase wells. The flow is diverted through the tool barrel, which raises the velocity of flow and increases the sensitivity so that they can detect rates as low as 10 to 15 bpd. Diversion of fluid into the tool barrel is accomplished by a skirt of fabric or metal leaves that are deployed to contact the tubing or casing wall. Often called basket flowmeters, the skirt exhibits little leakage even below tubing. Older tools used an inflatable packer to divert all flow through the tool.

For multi-phase flow, additional tools are necessary, such as the fluid capacitance or gradiomanometer log to assess water or gas comingled with oil.

This tool takes its flow measurement while stationary with the skirt in the open position. It can be pulled up to the next station without closing the skirt. A log is created by connecting the data points by straight lines.

A temperature sensor should always be included in the tool string as it has better vertical resolution than the spinner, so it can locate small inflows not seen on the spinner log.

The multi-capacitance flowmeter measures the velocity of fluid flow in a production or injection well by measuring the transit time of a disturbance between two dielectric sensors a fixed distance apart. The device is a type of crosscorrelation flowmeter that uses several pairs of capacitance, or dielectric, sensors held on an arm to span the borehole.

An array spinner with array capacitance is being developed, which would be especially helpful in highly deviated or horizontal wells.

 

Fluid density (track 1) and spinner survey (tracks 2 and 3). Well flowing 10,000 bpd. Density shows water density in sump below perfs, oil density over perf interval. Spinner shows increasing cumulative production over lower half of perfs. The upper half of the perfs may have been ineffective or the reservoir quality is so poor that no flow can be expected. A competent forensic  petrophysical analysis could answer this question and a workover initiated if warranted. Amplified fluid density curve shows slight decrease up to 7160 feet indicating some water in the oil below this depth - this is the "water holdup".

MODERN INTEGRATED PRODUCTION / FLOWMETER LOGS
Numerous service providers have offered flowmeters in combination with fluid density, temperature, pressure, natural gamma ray, and tracer logs for many years. In two-phase flow, these logs are quite adequate in many cases, even in some horizontal wells in which the flow regime is reasonably well behaved.

However, understanding horizontal flow can be quite challenging and more sophisticated tools may be helpful. These include all the usual sensors as well as some new ones, with some arranged in fixed arrays to show horizontal flow and three-phase flow in considerable detail.

Layered flow often occurs in high angle wells, with a water layer in the lower part of the wellbore cross-section, an oil layer above the water, and a gas layer at the upper part of the cross-section. One objective of the integrated tools is to create an image of the actual flow regime.

The following tool description is based on the Schlumberger Floview Plus tool introduced in the mid 1990s. The description is condensed from PetroWiki and the examples are from Schlumberger.

There are three key components to the tool. First is a full-bore spinner. This item gives information about composite fluid velocity.

The second component is called Floview Plus. The main results from this tool are eight-electrode measurements of water holdup to provide an approximate image of how the fluids are segregated in the cross section of the casing. The fluid image greatly aids in the interpretation of the spinner response.

The tool uses matchstick-sized electrical probes to measure the resistivity of the wellbore fluid, high for hydrocarbons and low for water. The probes are located inside the tool’s four centralizer blades to protect them from damage. Opening of the blades positions each probe at midradius in the casing. In some flow regimes, both water holdup and bubble-count measurements may be obtained from the output of the probe.

Local water holdup is equated to the fraction of the time that the probe is conductive, whereas bubble count comes from the average frequency of the output. The local water holdup from each of the eight probes is used to generate the water/hydrocarbon distribution in the well’s cross section.

The third component is the Reservoir Saturation Tool, often run in conventional cased hole logging programs to assess the current state of the reservoir. This tool is a pulsed-neutron log that can be operated in nuetron-lifetime mode or spectral carbon/oxygen mode. Its main applications are for estimation of oil, gas, and water holdups and determination of water-phase velocity by oxygen activation.

From a combination of the holdups, the cross-sectional area of the wellbore, and the fluid velocities, the rates of the individual phases are estimated as a function of position along the wellbore’s axis.
 

On the right of the gamma ray and depth track, Track 2 displays water holdup from the FloView Plus tool and three phase holdup log (TPHL). Stationary measurements and continuous logging results are plotted from both. Tracks 3 and 4 are TPHL log oil and gas holdup data. Track 4 is the FloView Plus two-phase measurement plotted along the trajectory of the horizontal section of the wellbore. Track 6 is a similar plot of TPHL log holdup data for all three phases along the wellbore trajectory. Track 7 is a flow rate profile computed from TPHL log holdup data and the FloView Plus tool's velocity measurements. The perforated interval is indicated between Tracks 6 and 7.


The water holdup plots of the TPHL log and FloView Plus tool's data agree well over most of the interval. Above XX,500 feet, however, the FloView Plus tool is unable to measure the small water flow values because of high water velocity and low holdup. The highest point in the horizontal section of the well occurs at approximately XX,560 feet. Little fluid is produced from below that point, resulting in high water holdup in the bottom of the well. From XX,560 to XX,800 feet, where the fluids are flowing downward, oil and water travel faster than gas and, consequently, have lower relative holdup rates. The insensitivity of the TPHL log's measurement to fluid velocity or droplet size makes it possible to detect condensate in mist flow or, as in this case, high-velocity water flow at low holdup. Above XX,800 feet, the well becomes more vertical, slowing the oil flow and increasing its holdup.
 

SYNTHETIC FLOWMETER LOGS  
Optimizing perforation interval or horizontal well placement can be aided by creating a cumulative flow capacity curve, based on the permeability derived from the petrophysical analysis of the prospective pay zone. The KH% curve is presented with 0% at the left and 100% on the right. This will match the shape of a spinner flowmeter survey, with zero flow capacity at base of pay and 100% at top of pay.

Intervals with the steepest slope on the KH% curve are the most productive and should be perforated if not too close to water or gas. Where the KH% curve is near vertical, no perfs are required.

Place horizontal well at or slightly below midpoint of the steepest slope of the KH% curve. This may vary depending on frac design and rock mechanical properties.

Permeability does not have to be well-calibrated to use this technique since the KH% curve is normalized between 0 and 100%.

Grid lines are 1 meter spacing. Tracks 1, 2, 3 show GR, SP, PayFlag, resistivity, PE, neutron, and density porosity. Calculated and core porosity in Track 4 with saturations in Track 5, calculated and core permeability in Track 6. Note excellent match to core data (coloured dots). Higher SW in lower zone is due to finer grained sand, not transition to water. KH% in Track 7 starts at base of PayFlag and runs up to top of PayFlag. Arrow shows base of perforations. KH% curve shows 40% of possible flow capacity has not been perforated. Since this is a gas expansion drive reservoir, the perforations should be extended 2.2 meters to capture at least 30% more flow capacity.