Production Logging of Multiphase Flow in Horizontal Wells

Case Studies

This section discusses production logging examples obtained from three major logging companies. The first example shows how conventional logging tools obtain useful information in horizontal wellbores. The other case studies describe examples of logs obtained with tools developed especially for the horizontal logging environment.

Western Atlas – Conventional Production Logging Tools

Despite challenges imposed by horizontal wellbores, early log runs with conventional production logging tools proved useful in obtaining important diagnostic information. Though conventional tools were not able to provide the detail needed to analyze multiphase flow, they were quite capable of pinpointing water entry locations (for isolation to reduce water production), and they were also able to characterize flow to a limited extent. The paper presented by Nice at the 1992 World Oil Horizontal Well Conference describes how conventional logging tools were used to qualify fluid type and flow rates in an effort to optimize remediation efforts in a horizontal well.

A major operator drilled a horizontal well in the Gulf of Mexico with 1300 feet of horizontal displacement. The 8.5-inch wellbore was completed in an unconsolidated sand formation using a 7-inch uncemented liner and 721 feet of prepacked screen spaced over an interval of 831 feet. The production liner consisted of five prepacked screens, each separated by a 20 foot section of blank pipe (Figure 1 – Schematic of horizontal well).

The unconsolidated sand of the producing zone was expected to collapse around the liner. Because openhole logs indicated that the wellbore had penetrated a water sand, the operator installed two check valves below the screens when the liner was set 257 feet off bottom.

The well initially produced 1300 STB/D of oil, 300 B/D of water, and 800 MCF/D of gas. Within 6 months, however, production changed drastically. Oil production declined to 350 STB/D, while water production increased to 1700 B/D.

The operator ran a suite of conventional production logs to determine water entry points, production rates, and the extent to which the unconsolidated sand collapsed around the liner.

The operator selected Western Atlas to log the well, and the following tools were run on coiled tubing:

• Radioactive isotope injector (Flolog): provided total flow profile
• Oxygen activation (Hydrolog SM): provided water (only) profile
• Surface readout pressure (SRP): provided flowing/shutin pressure
• Gravel pack evaluation (Photon): provided borehole integrity evaluation

Log Measurements

The Flolog indicated fluid entry at screens 1, 2, 3, and 5 (numbered from the bottom up) (Figure 2 – Results of log run).

Screen 1 accounted for a total flow of 1700 B/D near its center. The upper quarter of screen 2 and all of screen 3 combined to contribute 3500 B/D. No additional flow was measured along screen 4. The upper two-thirds of screen 5 produced 2500 B/D, but no flow was measured in the lower portion of the screen. The total flow rate above the screened section was measured at 2200 B/D. Velocity measurements from the Flolog do not account for water fallback, holdup, or the wellbore space occupied by each phase as the rate is calculated.

The Hydrolog measured a similar profile to the Flolog, but three points produced at flow rates that exceeded the tool’s measurement capability. An entry of 1300 BWPD is indicated at the midpoint of screen 1. The upper end of screen 2 produced 2000 BWPD, just below the major influx indicated on the Flolog between screens 2 and 3. The water rate above this point averaged 1300 BWPD to the upper end of the screened section.

Pressure measurements from the SRP tool were used to compare downhole shut-in pressure and flowing pressure. This comparison revealed a pressure differential of 470 psi. Along lower points of the wellbore, a 5 to 7 psi increase in flowing pressure was attributed to additional water holdup.

The Photon log indicated that unconsolidated sand in the producing formation had indeed collapsed around the liner in all but two intervals, located along the upper part of the undulating wellbore. The collapse effectively restricted annular flow outside the screen. The voids found on the photon log correlated to zones of higher shale content shown on openhole logs. Increased shale content may have contributed to formation strength and borehole stabilization along intervals that did not collapse around the screen.

Observations

Total flow rates were greater than total production at several points within the wellbore. Rates at these points were measured several times for verification, and were measured again after a stabilizing flow period. The production profile was constant over a total monitoring period of about 8 hours. A directional survey was plotted on the log, which helped to show that these high velocities were found near higher elevations of the undulating wellbore. In these intervals, the water fallback, produced water, and oil all shared the available annular space. Under these flow conditions, the velocities of the oil and gas phase accelerate until the wellbore changes to a more neutral angle.

A comparison between the water (only) profile and the total flow profile showed a difference in flow rates that was attributed to oil production. This conclusion is supported by lower flowing pressure measured by the SRP, which would indicate lower water holdup. The total flow rate revealed major production entering at the upper end of screen 2 and the entire screen 3 interval. Additional production was indicated at the upper two-thirds of screen 5.

Recommendations

Based on these interpretations, the operator elected to isolate the water zone producing through screen 1. Coiled tubing was used to insert an inflatable bridge plug at the portion of liner between screen 1 and screen 2. After setting the bridge plug, water production decreased by 1200 B/D, while the oil rate increased by 500 STB/D.

Conclusion

This example shows that conventional tools were not used to measure flow rates for each phase, yet they still worked well in the presence of multiphase flow and undulating borehole conditions. These logs were used to identify the primary water entry point so that it could be isolated. By qualifying fluid type and flow rates, the operator was able to take appropriate remedial action to substantially improve well production.

Schlumberger – Flagship Production Logging Service

Figure 3 – Comparing FloView Plus and RST three-phase holdup measurements, shows a cased, cemented, and perforated completion, logged by Schlumberger Oilfield Services.

This newly drilled horizontal well was producing 95% water and had twice the gas oil ratio of neighboring wells. The operator suspected that the well was producing free gas through a fault connected to the gas cap.

Here, Schlumberger’s FloView Plus and the RST three-phase analysis package were run. The well contour is plotted on the vertical depth scale, and clearly shows an undulating wellbore. Both the RST and the FloView imaging show that water is the dominant phase in the uphill portion of the leftward-moving flow. As the water flows over the crest, the oil holdup increases dramatically, even though no perforations are present. This effect is, of course expected.

The FloView resistivity probes cannot differentiate between oil from water, but the RST can. The RST shows the presence of gas beginning suddenly at the perforations located at in the vicinity of 720 ft. Since it occurs midway along the down-slope and stays approximately constant, the data implies that this particular set of perforations is contributing the gas. The holdups are not usually sufficient to conclusively make an interpretation, and velocity data is typically also required.

Halliburton – Gas Holdup Tool

Figure 4 – Flow regime and water fallback, shows how bubbles and mist are detected.

The bottom of the log shows agreement between gas holdup curves derived from the center-sample fluid density tool (YG curve), and from the fullbore Gas Holdup Tool (YGHT curve). This data, combined with the fullbore flowmeter data indicate small bubbles dispersed throughout the fluid in a bubble flow regime.

At the perforation just below X230, we see separation between the YG curve and the YGHT curve, caused by water fallback. The fluid density tool, being a center-sample device, measures a higher gas holdup. The GHT shows a lower gas holdup as water falls back along the casing wall. This water is not being lifted to surface. Near the top of the log, the agreement between the YG curve and the YGHT curves, combined with the flowmeter data, indicate mist flow, with a high percentage of gas, and a very low amount of water, dispersed as mist.