Implementation of Customized Algorithms Extends Downhole Flowmeter Application in Two-Phase Oil/Gas Flow: A Subsea North Sea Case Study
- Tatiana Kiryushkina (Centrica Energy) | Ali Shahbaz Sikandar (Centrica Energy) | Martin Rafael Figueroa (Schlumberger) | Adam Charles Vasper (Schlumberger) | Emmanuel Philippe Balster (Schlumberger Oilfield Services) | Joseph Albert Eck (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- Brasil Offshore, 14-17 June, Macaé, Brazil
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 4.2.4 Risers, 5.1.5 Geologic Modeling, 4.5.3 Floating Production Systems, 5.3.2 Multiphase Flow, 1.6 Drilling Operations, 5.5 Reservoir Simulation, 4.2 Pipelines, Flowlines and Risers, 5.2 Reservoir Fluid Dynamics, 4.1.5 Processing Equipment, 4.4.3 Mutiphase Measurement, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 6.5.2 Water use, produced water discharge and disposal, 5.2.1 Phase Behavior and PVT Measurements, 1.10 Drilling Equipment, 3.3 Well & Reservoir Surveillance and Monitoring, 2.4.3 Sand/Solids Control, 5.6.4 Drillstem/Well Testing, 2 Well Completion
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The Chestnut field is located in Block 22/2a in the central North Sea. The field, with water depths to 120 m, is approximately 180 km east of Aberdeen, Scotland. Chestnut was first commercially produced in September 2008 by Centrica Energy (formerly Venture Petroleum) using two subsea wells (a horizontal oil producer and a water injection well) tied into a floating production, storage, and offloading (FPSO) vessel. Water injection was required almost immediately because the oil was saturated. A second oil producing well was spudded in September 2008, targeting the South Chestnut field. This well, 22/2a-16Y, was tied into the same flowline and riser as the existing oil producer.
A venturi-type downhole flowmeter was installed in well 22/2a-16Y to obtain continuous pressure, temperature, and flow rate measurements. The production from the other well could then be calculated by subtracting the venturi flowmeter measurements from the total rate measurements made at the FPSO.
Venturi-type downhole flowmeters are, strictly speaking, only applicable in liquid environments because the Bernoulli principle is valid only for single-phase flow and is tenable only in low-slip liquid-liquid flow regimes, such as in the concurrent flow of oil and water at high velocities. Because the Chestnut oil is saturated, it was known that free gas would be seen at the intake of the venturi because the flowing pressure would, by definition, be below the bubblepoint.
To address the challenges caused by two-phase flow through the flowmeter, a workflow was developed that would first assess the quantity and affect of the free gas in the venturi device. The workflow was then developed to increase the accuracy of the flowmeter in the two-phase oil-gas flowing conditions. The enhanced flow calculations were then validated by using FPSO test separator data when only the flowmeter-equipped well was producing. The enhanced model improved the accuracy of the liquid-rate predictions across various rates from initial discrepancies of 40% to 190%, to less than 5%, allowing Centrica Energy to achieve its well- and reservoir-monitoring objectives.
The use of venturi-type flowmeters has traditionally been limited to applications in which only liquid is flowing through the meter. This present case study shows that customized workflows can improve the accuracy of the venturi flowmeter measurements in multiphase environments, making these downhole flowmeters a cost effective alternative to true multiphase meters for certain applications.
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