New Logging Tool Enhances Multiphase Production Analysis

A new multifunction production logging (PL) platform is producing quantifiable results in complex triphasic flow regimes. At 25 ft long, the system takes the place of a conventional PL tool string five times as long. The Schlumberger Flow Scanner tool, unlike its predecessor, features close integration of its 17 sensors in an 11-ft-long sonde so that true dynamic flow characteristics can be obtained at any point in the well. The new system is designed to operate in well-bore diameters ranging from 2 7/8 to 9 in. and under environmental conditions up to 300°F and 15,000 psi. This technology is particularly valuable in deviated and horizontal multiphase wells, where phase behavior is extremely variable and complex. To obtain an accurate picture of the dynamic flow regime at any point in the well, it is necessary to scan the full diameter of the wellbore. The new logging tool does this mechanically, electrically, and optically. (Fig. 1).

Fig. 1—The articulated Flow Scanner sonde finds the low side of the wellbore. The lower arm deploys four minispinners at equal intervals across the hole -diameter (a fifth spinner is contained in the sonde body). Resistivity and optical sensors spaced across the upper arm measure water and gas holdup, respectively. As a result, the full diameter of the producing bore is scanned, resolving any flow regime at any angle.

Run eccentered in open or cased holes, the tool finds the low side of the hole thanks to gravity. Then an articulated sensor arm is deployed that spans the wellbore, providing five equally spaced measurements of flow velocity, direction, and phase fraction. Together, these measurements provide three-phase holdup, which is defined as the dynamic phase fraction at any point in the wellbore. Holdup differs from produced volume fraction, or cut, because the phases travel at different velocities. Other tool sensors measure pressure and temperature, hole diameter, and instantaneous tool orientation.

To analyze a production interval properly, one must understand exactly what is happening at each spot in the well-bore. Previous PL methods interfered with the flow regime they were trying to measure, and typical phenomena such as heavy-phase recirculation resulted in ambiguous data with gaps over critical intervals. In addition, interpretation could take months and involved dozens of specialists examining data from several log passes. In contrast, the new log-ging tool was designed using computational fluid-dynamics simulations to optimize its shape and minimize any flow perturbations. A real-time graphics display and processing workflow makes preliminary interpretation possible with a single logging pass. One or two additional passes at different logging speeds can enhance overall accuracy.

Proving the Process

In a multilateral maximum-reservoir-contact well in the Middle East, the tool was used to determine lateral contribu-tions and well performance, and to detect any water present. A tractor was used to convey the tool down the 4-in.-diameter wellbore, and logging was completed in a single downward and upward pass. All logging was conducted in the motherbore because it was not possible to convey the tool into each lateral. However, it was important to know the phase contribution of each lateral and whether any production was being diverted into “thief” zones. The well was logged with two different choke settings, and the data from the new tool accurately reflected the effect of changing the choke diameter on production behavior in situ (Fig. 2). The operator concluded that the integrated PL measurements could be used together with near-wellbore modeling to characterize the reservoir more accurately, in particular to help identify crossflow and quantify individual layer permeabilities. It also was concluded that the measurements could be used to optimize choke sizes for better production and drainage strategies.

Fig. 2—Lateral contributions are evaluated for various choke sizes, allowing the operator to fine-tune production in this maximum reservoir contact well.

Several openhole horizontal completion examples illustrate the value of integrated PL measurements. In these cases, the 85- to 93-ft-long tool strings were conveyed by tractor and by coiled tubing. The field examples were from a large Middle East carbonate reservoir being produced on waterflood. As a result, produced water was often a mixture of formation and injection water. Logs were run to determine the point(s) of water entry and the flow profile. The first three wells were logged using an integrated PL tool string. While some good results were obtained, the operator reported clear limitations of the integrated system. Specifically, in horizontal sections where there was phase separation, it was impossible to quantify the phase holdup using spinner data. Numerous logging passes were required to acquire data from individual tools in the string. Interpretation was time-consuming and complex, and conclusions largely relied on inference from numerous indicators rather than reflecting direct measurement.

For the fourth well, the operator was able to use the new logging system, which had just become available. The well was completed in a 6 1/8-in. open hole and initially flowed dry oil. After several years, the well was producing at 40% water cut, and just before logging, the cut had increased to 51%. The well was completed through four layered zones of different permeabilities using a 2,500-ft-long drainhole. As in the previous wells, the objective was to determine the water-entry intervals and the flow profile.

The job was planned for a single-trip pass with the tool conveyed by coiled tubing and data acquired in the downward and upward directions. Additional passes were an option, but with images from the new logging tool integrated with existing openhole log data in real-time, it would be possible to reach many conclusions after the first pass. Sufficient information was recorded on that pass to allow judicious selection of any intervals where additional short passes were required. This reduced total operating time to 15 hours. Original openhole logs had identified numerous fractures as open, or conductive. In fact, the PL logs using the new tool showed that 58% of the water was coming from a single fracture near the base of the interval, and the remaining 42% was coming from a few closely grouped fractures. Some of the previously indicated open fractures were discovered not to be contributing any fluid at all.

Information provided by Schlumberger and Saudi Aramco.