Fiber optics provide the ideal medium for downhole production monitoring. Fiber optic systems are capable of making multiple downhole measurements and transmitting them to surface in real-time with only a single wellhead feed-through. This latter feature proves extremely valuable when installing a fiber optic production monitoring system on an existing wellhead or one that is producing from multiple discrete zones. They provide excellent support for intelligent completions.

Fiber optic pressure and temperature sensors have been around for some time. Lightweight and passive, they have proven to be reliable and cost-effective. There are no moving parts, and sensors do not experience drift as gauges often do over time. The sensors consist of Fiber Bragg Gratings (FBG), which are inscribed right into the fiber. During the manufacturing process, an ultraviolet light source is used to modulate the refractive index of the fiber at the point where the gauge is to be located. This creates a sensor with specific wavelength sensitivity - called the Bragg wavelength. When a light pulse is introduced from the surface it travels down the fiber and is partially reflected by the grating. The reflected light signal returns to a surface pick-up device where its characteristic properties are recorded. The FBG's wavelength shifts according to applied temperature or pressure and has a linear response is linear over a wide range of temperatures and pressures. Optical sensing offers a reduced noise sensor that is unaffected by electrical interference.

A recent extension of fiber optics technology is Distributed Temperature Sensing (DTS). This consists of a multi-mode fiber that allows for precise temperature profiles of an entire well to be recorded. Signal processing equipment at surface is able to deconvolve the complex signals from the DTS fiber so a clear profile emerges, enabling analysts to detect water or gas coning or to model formation flow profiles.

A valuable application of fiber optics is in flow measurement. Because of their inherent ruggedness, a fiber optic flowmeter (FOFM) is particularly well suited for use in harsh environments. Because they are electrically passive and because they have no moving parts, fiber optic flowmeters offer excellent reliability in a variety of applications. Advanced versions are able to discriminate multiphase flow and phase fraction (holdup). In addition, real-time downhole multiphase flowmeters can supply critical information key to production and reservoir optimization.

Several applications exist:

• Allocation of zonal production, in commingled completions;

• Zonal allocation of water or gas (or WAG) injection in multi-zone intelligent completions;

• Identification and pinpointing of localized problems;

• Direct determination of productivity index (PI);

• Monitoring and control of new well clean-up, or following intervention; and

• Reduction of surface testing and production facilities.

Proving the principle

Historically, the tough downhole environment made traditional flow measurement solutions difficult to achieve. Thus incentivized, scientists at the Graduate School of Environmental Studies of Japan's Tohoku University built prototype FOFMs for study and analysis. The team built flowmeters using a series of four FBGs. Two of the FBG record temperature and pressure respectively, the other two record flow velocity, hence volumetric flow rate. The flow gratings measure strain in two vortex shedding cantilevers that acted like a tuning fork positioned in the flowstream. Bulk fluid velocity is calculated by making a cross-correlation (time delay) of the Bragg wavelength shifts of upstream and downstream sensors and by establishing the Karman vortex shedding frequency. Both the cross-correlation velocity and Karman vortex shedding frequency increase linearly with bulk flow velocity. Since the frequencies being measured are so high, accurate flow measurements can be determined even with an upstream/downstream sensor interval of only a few millimeters in most cases. The sensor interval can be expanded to accommodate very high-velocity flow. Minimum detectable flow varies depending on the coherence between the upstream and downstream vortex shedding frequencies, but with good coherence flows as low as 0.1 fps (0.03 m/s) have been recorded with reasonable accuracy.

Practical field solutions

Several companies are working to develop practical fieldworthy tools. Weatherford has made progress on several fronts to expand its capabilities. Besides standard pressure and temperature measurements, the company has developed DTS, downhole seismic and unique FOFM technology. After extensive flow loop testing in a wide variety of fluids and flow conditions, the first commercial installation of a practical FOFM was made by the company on Shell's Mars A-18 well in the Gulf of Mexico in October, 2000. Since then, several installations have been made worldwide. Weatherford's device is considerably different from the scientific prototype described above. Instead of placing cantilevers in the flowstream, the company has developed a way to use an acoustic sensor array to listen to natural production noise. The technique has a major advantage in that there are no obstructions or Venturis to restrict access below the meter. This means that it is possible to run production logging instruments or other intervention devices through the tool.

How it works

The fiber optic flowmeter makes two primary measurements: the momentum averaged flow velocity and the speed of sound in the flowing mixture. These measurements are based on unsteady pressures associated with turbulent flow and naturally occurring acoustics. This includes acoustics generated by turbulent boundary layers, production flowing through perforations, downhole chokes, electrical submersible pumps (ESP), and gas lift devices.

An array of externally mounted and axially distributed pressure sensors detect pressure fluctuations caused by the natural generation and collapse of vortices in the measured fluid. Extremely accurate in single-phase measurements, the tool typically measures bulk flow velocity within ±1%, and can be calibrated to within ±0.25%. From the unsteady pressures, the speed of sound of the flowing mixture is also measured. Using a physical model for mixture bulk modulus, in-situ phase fractions of oil, water, and gas can be determined. Extensive flow loop testing has determined that the acoustic technique works very well for both oil/water and liquid/gas mixtures. In multiphase flows, the accuracy of the device is within ±5% across the full range of water cuts, and accuracies on the order of ±2% have been achieved on ESP installations, according to the company. Unaffected by solids in the stream, the device can even be used to measure slurries.

The Weatherford tool is bidirectional and gives both rate and flow direction. This is ideal for use in flow allocation in multi-zonal production or injection wells and in fluid or gas environments. It has also enabled detection and quantification of interzonal cross-flow in one injection well.

Real results

BP successfully demonstrated the value of real-time downhole production data in March, 2002, when it installed a FOFM in its MA-15 well in the Mahogany field offshore Trinidad. Set at 12,114 ft (3,693 m) measured depth and 71° deviation, the FOFM recorded several "firsts" for the company, including the ability to resolve complex flow regimes involving high downhole shear rates. Other pioneering achievements included first application involving a downhole flowing gas phase, first multiphase installation, first permanent walk-away installation of surface flowmeter instrumentation and first installation to use a network accessible hard drive to provide data access across a wide area network. The FOFM uses the measured mixture sound speed, together with knowledge of pure phase densities and sound speeds (from production analysis and empirical correlations), to determine the volume fraction of each phase at the meter. Phase fraction and bulk velocity measurements are combined to determine phase flow rates. Data from the MA-15 well have been applied in a number of ways to gain insights into well production and its influence on the reservoir. By understanding the complex flow regime in real-time, BP was able to manage the ramp-up phase to establish optimum flowing tubing pressure. With real-time flow data, every shut-in became an opportunity to evaluate well performance, and the value of well test data was greatly enhanced. The availability of continuous downhole pressure, temperature and flow data helped identify and analyze reservoir effects ordinarily invisible to surface instrumentation. And production anomalies anywhere in the field showed up on the data, giving insight into their cause and possible effect.

Building on the company's experience with two-phase FOFMs, a new three-phase version was installed in BP's North Sea Mungo platform in May, 2003. Essentially, the three-phase FOFM consists of a multiphase FOFM plus two fiber optic pressure gauges vertically separated by about 150 ft (45 m). This provides independent measurements of mixture density and the mixture speed of sound (Figure 1). Installed in well # 176 at 5,088 ft (1,551 m) total vertical depth and an angle of 63°, the flowmeter provides pressure/temperature (P/T) readings every second and oil, gas and water flow rates every 2 minutes. The device has been operational for two years, and continues to give real-time flow rates. The non-intrusive, full-bore technology is scalable for any size production tubing.

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