Production logging tools developed for vertical or near-vertical wells may not present a true picture of flow dynamics in highly deviated or horizontal well scenarios. Drilling of nonvertical wells has revealed a need for more sophisticated downhole flow analysis instrumentation, particularly for multiphase flow. The Schlumberger FloScan Imager production logging system has been designed to address this requirement.

In vertical wells, phases tend to be evenly mixed across the well bore. This holds generally true for deviations less than 20˚ - oil and water mix across the entire well bore, with oil, the lighter phase, increasing on the upper side of the well bore. The velocity profile is smooth, and the water holdup profile varies gradually across the pipe. Averaged measurements are adequate to determine the velocity and holdup with this type of flow

Beyond 20˚, flow dynamics change significantly, and measurements in the center of the well bore may be inadequate - especially for multiphase flow profiling (Figure 1). In highly deviated wells, phase layering occurs, creating a problem for production logging instrumentation designed for vertical wells because the instruments rely on measurements taken from the center of the well bore.

In a multiphase, highly deviated well, the result may be data acquisition only for the phase whose layer happens to be at the center of the well bore and providing insufficient information on the phases flowing on the upper and lower sides of the well, hence generating an incomplete picture of the flow dynamics.

Study results in non-vertical wells

In wells with deviation between 20˚ and 85˚, overall flow structure becomes more complex. Water, the heaviest phase, migrates to the lower portions of the well bore, and the mixing layer is on the upper side, with dispersed bubbles of oil. In wells with deviations between 85˚ and 96˚, oil/water flows tend to be stratified. Water flows at the bottom and oil on the top. At flow rates as high as 20,000 bo/d in a 5-in. liner, there is little mixing. At lower flow rates, the flow demonstrates a strong dependence on well deviation. When gas is present, multiple flow regimes may be encountered, depending upon the extent of well deviation. Given a constant flow rate, the holdup - the proportion of pipe cross-sectional area a particular fluid occupies - and velocity profile of each phase will vary.

Biphasic (oil-water) experiments were conducted in a controlled flow loop with equal flow rates for oil and water, revealing dramatic effects of borehole angle on flow behavior (Figure 2). At 90˚, flow rates and holdups of oil and water were found to be nearly equal, with oil having a slightly lower flow rate and oil holdup being slightly higher than the water holdup. Even a slight deviation of the hole from 90˚ results in oil and water flowing at different rates. At high flow rates, increasing shear frictional forces against the wall and interface dominate, and the dependence on deviation is smaller.

At deviations less than 90˚ (uphill), water slows and oil velocity increases. The water holdup increases while the oil holdup decreases. Any gas present would begin to slug. At well deviation above 90˚ (downhill), flow is still predominantly stratified. The water flows much faster than the oil because of its higher fluid density. The water holdup now decreases while the oil holdup increases.

Downhole flow regimes in deviated boreholes can be complex based on the inflow of oil, gas and water phases and can include stratification, misting and recirculation. Strategies to optimize production require a more complete set of logging data than needed for vertical wells. When conventional tools are run in deviated wells and encounter topside bubbly flow, heavy phase recirculation or stratified layers traveling at different speeds, interpretation problems occur. Flow-loop studies also revealed shortcomings of center-measurement instruments in multiphase flows. Again, center measurements are inadequate for describing complex flow across the vertical diameter of the well bore. Such tools have sensors spread out over long distances in the well bore, making measurement of complex flow regimes even more difficult.

System specifics

The new system has been specifically developed for production logging in highly deviated and horizontal to near-horizontal wells. The heart of the system is a retractable arm on the downhole tool (Figure 3). On one side of the tool's retractable arm are four miniature spinners used to measure the well fluid-velocity profile. On the other side are arrays of five electrical and five optical probes for measuring localized water and gas holdups, respectively. Additionally, a fifth miniature spinner and a sixth pair of electrical and optical probes on the tool body measure flow properties on the low side of the well. All sensor measurements are made at the same depth simultaneously.

This horizontal and deviated production logging system is run eccentered, lying on the low side of the well with its arm deployed across the vertical diameter of the well bore. The arm is extended to a length equal to the diameter of the production tubulars, so it serves as a caliper, providing cross-sectional area measurements needed to calculate flow rates. The system operates in temperatures to 302˚F (150˚C).

The system is combinable with other wireline production platform services and other cased-hole logging tools.

Multiphase velocity profiling

Because the system measures the velocity profile at multiple points along the vertical diameter of the well bore, it can measure velocity variations that cannot be detected using a single, centered spinner. It provides measurements of mixed and segregated flow regimes, including direct independent measurement of gas velocity in a multiphase horizontal well. The tool can also detect the recirculation of water downhole.

This unique production logging system detects water by using six low-frequency probes that measure fluid impedance. Because water conducts electric current, whereas oil and gas do not, a threshold is set that enables the tool to distinguish oil and gas from water.

Each probe generates a binary signal when oil or gas bubbles in a water-continuous phase, or droplets of water in a hydrocarbon-continuous phase, touch the probe's tip. Water holdup is determined by the fraction of time a probe's tip is conducting, and the water holdup profile accurately represents the flow regime in the well bore.

This methodology enables a local water holdup measurement, independent of fluid properties, without any need for calibrations. Conventional tools require accurate calibration in oil and water. Further, the bubble count measurement - the log that represents the number of non-conducting events detected during a monitoring interval - can be used to locate fluid entries. Conventional tools also lack the accuracy to do this. Traditional low-frequency probes cannot distinguish gas from oil, while the new system is equipped with optical probes for gas detection.

Case history: Gulf of Suez

Aging reservoirs in the Gulf of Suez produce viscous oils at high water cuts through deviated to horizontal completions. Conventional production logging tools often have difficulty defining the complicated flow regimes and identifying areas for water shutoff to maximize oil recovery in a field as it nears its economic limit.

One well with an inclination of 37˚ was producing with gas lift through six open intervals. Production was 2,058 bo/d with 9,796 bw/d water cut. Figure 4 compares logs from the new imager with conventional production logging surveys. The flow profile shows that approximately 25% of the oil and 85% of the water were being produced from perforations below X400 ft (122 m). The remainder of the water and some oil were produced from perforations at X390 ft (119 m). The two perforations above X390 ft (119 m) were producing clean oil, and more than half of the oil was flowing into the top perforation.

Conventional production logging sensors could not detect oil entering the top perforations because the spinner was affected by water recirculation, and the resolution of the gradiomanometer in the deviated well was too low for it to resolve oil contributions. The conventional survey erroneously attributed 90% of the oil production to the lower perforations.

On the basis of tool results, a workover operation was planned to optimize the oil production. After cross-referencing the log results with geologic information on the location of a sealing layer of shale, the operator set a plug at X400 ft (122 m) to isolate the majority of the high water-cut zones in the bottom of the well. The resulting production of 556 bo/d and 2,532 bw/d represented a nine-fold increase in oil production, and payback was accomplished in less than a week.

Scenarios such as this emphasize the significant benefits from gathering more complete and accurate flow data. Conventional flow profiling tools that were originally developed for use in vertical wells fall short when applied in horizontal and deviated wells. Data from strategically placed sensors can overcome the inadequacies of center measurement and provide accurate profiling of complex flow regimes.

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