Fluid identification logging in high angle wells

Layered flow often occurs in high-angle wells (i.e., 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). While the tools used in vertical wells have proven effective in high-angle wells on most occasions, special tools have been developed for studying two- and three-phase flow. These tools make use of arms to position electrodes across the casing diameter. Consequently, they are "blind" to flow outside a screen or perforated liner. The brief descriptions of these tools that follow are based on the limited published information and personal discussions with suppliers.

Special production logging tool types

Halliburton gamma-ray backscatter gas-holdup tool

*

The purpose of this instrument is to distinguish liquid holdup (the percentage of the wellbore cross section occupied by liquid) from gas holdup (the percentage of the cross section occupied by gas) and provide a cross-sectional average for the mixture.

The gamma-ray source is the same Cesium-137 isotope used in the gamma-ray densiometers. A shielded scintillation crystal detector receives its signal from radiation backscattered by the density of material around the tool. The tool is used primarily to differentiate between gas and liquids. The contrast in density between gas and liquid causes a large change in signal level, while the small difference between oil and water densities causes a correspondingly small change in signal level. The value used for liquid density in the holdup calculation does not make much difference as long as it is in the range common to liquids. Thus, the corresponding error in holdup is at worst 10 to 15% and probably better because only backscattered radiation is involved. To compensate for pipe size, variable spacing between source and detector and/or shield should be used to eliminate backscatter from the formation outside the pipe.

For a limited range of gas-holdup values, flow-loop data for the backscatter tool show a linear response over the range of the data. Sensitivity to small gas concentrations is sufficient. These data do not shed any light on the matter of compensation for variable pipe size, however. If formation backscatter is high, then the gas point will show a much higher count rate and the small difference in liquid signal at zero gas holdup will become a relatively large difference. In-situ calibration in a shut-in well is therefore recommended for this tool if it is to function quantitatively.

Baker atlas multi-capacitance flowmeter

This centralized tool includes a spinner flowmeter at its bottom end. The wellbore cross section is considered as being divided into eight levels, and a positive orientation section of the tool ensures that the levels are perpendicular to true vertical.

Twenty-eight capacitance sensors are deployed on "wings" from the tool in such a way that there are capacitance sensors spanning each of the eight levels. An array of capacitance sensors spans levels at a first position along the tool’s axis. Another array of sensors spans levels at a second axial position.

During logging, the various capacitance measurements for each level are recorded and converted to values for the gas, oil, and water holdups. An across-the-wellbore, bidirectional velocity profile is constructed from transit-time measurements of the capacitance sensors on Levels 1 and 2 (bottom levels) and 7 and 8 (top levels). The construction involves cross-correlation of some of the sensor responses. The spinner flowmeter provides velocity information related to the wellbore centerline. Stationary measurements can be made as well.

The holdups, the velocity profile, and the cross-sectional area of the wellbore are combined to determine the flow rate of each fluid as a function of the axial position along the wellbore.

A possible limitation is that capacitance sensors sometimes film in heavier oils; in turn, an oil film biases the capacitance measurements toward oil and gas and away from water. Another possible limitation is that the distinction between oil and gas may not be nearly as great as the distinction between oil and water. Finally, the concept of velocity determination from two measurements at the same radius along the axis supposes perfectly layered flow free of circulatory velocities. This condition, however, is at odds with the assumption of capacitive-event creation for cross-correlation.

Schlumberger Flowview

In a horizontal well, five types of segregated flow are usually defined. These are: stratified with a flat interface, stratified with a wavy interface, stratified with a bubbly interface, lighter phase slugging over the heavy phase, and one phase existing as bubbles in the other phase.

Because of segregated flow, the new tool string consists of both traditional and nontraditional sensors. Some of these sensors average over the entire cross section of the casing, whereas others make measurements at different locations in the cross section. The various sensor sections are referred to as "items" in the description that follows. The tool string described next is for mainly oil/water flow. For three-phase flow, a larger tool string, called the Flagship (Schlumberger), is available.

• Item 1 is a full-bore spinner. This item gives information about composite fluid velocity, which in multiphase flow is difficult to relate to fluid-flow rates even after an image of the layers in the well has been generated by an imaging sensor such as the Flowview Plus (Schlumberger).

• Item 2 is the Flowview 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. The fluid image greatly aids in the interpretation of the spinner response.

This item consists of two Flowview tools, combined so that one is rotated 45° to the other and separated from it by at least 3 ft. Each Flowview makes four independent measurements of borehole fluid holdup and bubble counts, distributed in different quadrants of the pipe cross section. The tool is self-centralized and 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. The opening of the blades positions each probe at midradius in the casing. The tool can run up to 9 5 / 8 -in. casing.

Each probe is sensitive to the resistivity of the fluid that impinges upon its sharp leading edge. If the fluids are distinct and not in a fine droplet emulsion form, and the bubble size is larger than the tip of the probe (less than 1 mm), then 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.

• Item 3 is the Reservoir Saturation Tool. This tool is a pulsed-neutron tool that can be operated in 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.

• Item 4 consists of pressure, temperature, and deviation sensors. In addition to the spinner, these are the sensors found on traditional production-logging tool strings. The new string, however, locates the temperature sensor nearly 15 ft from the end of the string, making the measurement subject to interferences from fluid mixing by tool movement.

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.

The small resistivity probes tend to film with oil when in use in heavier oils and with water in gas/water flow. In these cases, the measurements of the affected probes are biased toward the filming phase.

* Personal communication, Halliburton (1993).

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See also

Production logging

Types of logs

Fluid identification and characterization

PEH:Production_Logging