Well Surveillance with a Permanent Downhole Multiphase Flowmeter
- Michael J. Webster (BP) | Simon M. Richardson (BP Exploration) | Celine Gabard-Cuoq (Schlumberger) | John Fitzgerald (Schlumberger Cambridge Research) | Kenneth E. Stephenson (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2006
- Document Type
- Journal Paper
- 388 - 393
- 2006. Society of Petroleum Engineers
- 3.3.1 Production Logging, 5.6.11 Reservoir monitoring with permanent sensors, 5.2.1 Phase Behavior and PVT Measurements, 5.6.4 Drillstem/Well Testing, 4.4.2 SCADA, 4.1.2 Separation and Treating, 1.10 Drilling Equipment, 4.6 Natural Gas, 5.2.2 Fluid Modeling, Equations of State, 5.3.2 Multiphase Flow, 4.1.5 Processing Equipment, 1.6 Drilling Operations
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Flow rate and fluid type (phase) are two of the most fundamental parameters needed to characterize well performance. Traditional methods of estimating these parameters, particularly for real-time detection and diagnosis of production anomalies, have been limited by sampling frequency and data quality. This paper presents field-test results of a new type of downhole multiphase flowmeter, which confirm the value of permanent downhole metering. The meter contains only three sensors but is capable of direct multiphase-flow-rate and cut measurements without slip models, even in highly deviated, recirculating flow. The physics basis and flow loop tests are discussed.
Well monitoring, surveillance, and problem diagnosis are critical parts of the production business, and many production parameters are monitored in the process. Of these, flow rate and fluid type (phase) are two of the most fundamental measurements. Over the years, many instruments have been used to collect and process flow data, including production-logging tools, surface-test separators, and surface multiphase flowmeters, but none of these provides a complete information solution.
Production logs provide flow information as a function of depth, but only intermittently in time. In addition, production-logging tools are complicated, especially those designed for deviations beyond 45° from vertical, in which sophisticated hardware with arrays of sensors must be combined with empirical slip models to cope with nonuniform and unsteady flows. Nevertheless, production-logging tools are routinely used to update reservoir models and diagnose problems. In some cases, problems are discovered when using these tools that would never be diagnosed on the basis of surface measurements (Lenn et al. 1998).
A traditional method of flow analysis relies on routine periodic production testing through a separator and back allocation of production over the intervals between tests. Restricted access to a test separator often imposes constraints on when this information can be gathered, and the empirical relationships used to estimate rate between valid tests are often hampered by errors and uncertainties associated with varying flow conditions and data limitations.
Finally, surface multiphase flowmeters may have limitations when gas/oil ratio (GOR) is high because of the high volume of associated gas that evolves from the liquid stream as it flows up the well, complicating the determination of oil and water volumes. On platforms servicing many wells, there may not be enough room to install a meter on each well, thus preventing continuous flow-rate and cut measurements on each well. This introduces the same type of uncertainty because of varying flow conditions, as found in the test-separator method.
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