Every drop counts in oil, gas production

In the early years of production, many fields produce predominately oil. As the oil is depleted and pressure is reduced, fields become mostly gas-producing field toward the end of their lives. Production from multiple zones in a reservoir also can cause significant changes in the gas and water fractions (GVF and WLR) as well as drastic changes of fluid properties over time. For such fields it is common that a multiphase meter is required in the early years of production, while a wet gas meter is needed later in the field’s life. In other cases, such as gas-lifted wells or long horizontal wells at low pressure, the GVF can continuously change from multiphase to wet gas conditions, referred to as slug flow. For these applications, the GVF changes from a very low gas fraction to almost 100% gas in seconds. These conditions, typical for many field applications, traditionally have made it difficult to measure the gas and oil flow accurately.

For wet gas applications, the challenge is accurately measuring small liquid fractions in a gas-dominated production stream. Once the liquid volumes have been measured, the small liquid fraction then must be split into water and oil. A metering system capable of extremely high resolution is required for this task. Additionally, operators often would like to know the conductivity and salinity of the produced water to determine the source.

Metering solution
FMC Technologies Inc.’s subsidiary Multi Phase Meters AS (MPM) was established when its founders recognized a need for a new method of measuring the constituents and flow rates of a production line (including oil and gas rates, water cut, and salinity). MPM has identified a technique called process tomography, commonly used in other industries, as a potential application for oil and gas operators.

In 2004, after receiving funding from various oil companies, MPM began developing prototypes for their first multiphase meter. The basic concept was to send and receive electromagnetic waves in multiple planes over a wide frequency spectrum through the fluids inside the flowline. The technology development has benefited from the consistent and active involvement of experts from oil companies, and initial tests were successful. The result: meters that are almost as accurate as single-phase meters that can be deployed quickly and more cost-effectively than conventional systems for both topside and subsea applications.

Compact FMC multiphase flowmeters are easily installed on the decks of offshore production facilities. (Photos courtesy FMC Technologies Inc.)

The MPM meter is based on patented and licensed technology using a combination of a Venturi flowmeter, a gamma detector (with an energy level of 662 keV and associated half-life of 30.7 years), a multidimensional/multifrequency dielectric measurement system, and advanced flow models that are combined into a multimodal parametrical tomographic measurement system. Tomographic technology improves the accuracy and measurement range for multiphase meters. One aspect of the MPM meter is its self-calibrating feature, which allows in-line measurement of water salinity and gas properties. This provides an immediate correction for fluid property changes occurring in the field, making the meter robust to these common changes and improving the accuracy of measurements.

The central technology of the MPM meter is marketed as 3-D broadband. The system is a high-speed electromagnetic wave-based technique measuring the water/liquid ratio, the composition, and the liquid/gas distribution within the pipe. The meter can measure fluids and gases under extremely high temperature and pressure. The mixture can move at velocities exceeding 98 ft/second (30 m/second) inside the pipe where the amount of gas, water, and oil are unstable and changing. Combining the information with measurements from the Venturi and the gamma densitometer determines accurate flow rates of oil, water, and gas.

For slugging flow regimes, the MPM meter can automatically switch up to five times/second between the multiphase and wet gas modes, bridging a gap previously not covered by multiphase meters. Using DualMode automatic switching between multiphase and wet gas measurements, one meter can be used for the full field life even if the wells change from predominantly oil to predominantly gas, and as the water cut increases later in the life of the well.

Raw measurement data are collected more than 100 times/second, and oil, gas, and water flow rates are calculated and can be presented up to 10 times/second. Averaging measured raw data is limited to avoid errors due to non-linearity in the flow. With its dual mode functionality, both multiphase and wet gas applications are addressed with the same hardware and software, bridging the measurement gap between multiphase and wet gas meters.

Testing procedures
In 2007, ConocoPhillips purchased a topside MPM meter for a real-life field application test. In a blind test, the 5-in. meter was installed in series with the test separator for the wells on a test header. The gas outlet on the test separator was measured by a 10-in. Instromet Ultrasonic Q-Sonic 3S wet gas meter. The oil leg was measured by a Krohne 6-in. ultrasonic UFM 3030, and water was measured by a Krohne 4-in. Coriolis Optimass 7000.

A total of 15 wells could be routed through the MPM meter with average range of fluid and process characteristics:
• GVF: 88% to 97%;
• WLR: 1.5% to 48.0%;
• Gas/Oil Ratio: 10 to 43;
• Pressure: 292 to 321 psig;
• Temperature: 78.8°F to 205°F (26°C to 96°C);
• Oil Density: 6.759 to 7.01 lb/gal (0.81 to 0.84 g/cc) at 60°F (15°C) and 14.6 psia;
• Gas Density: 0.45 to 0.52 lb/ft3 (0.72 to 0.83 kg/m3) at 60°F (15°C) and 14.6 psia;
• Water Density: 8.59 to 9.18 lb/gal (1.03 to 1.1 g/cc) at 77°F (25°C) and 14.6 psia; and
• Water Conductivity: 50 to 170 mS/m at 77°F (25°C) and 14.6 psia.

The patented 3-D broadband technology of the MPM meter uses process tomography to accurately measure oil, gas, and water flow rates for any flow condition.

There was significant variation in the pressure, volume, and temperature properties for oil, gas, and water. The test also contained both oil- and water-continuous wells with stable flow and slug flow conditions. The measurements from the multiphase meter and test separator were compared at process conditions without flashing the data to standard conditions. This approach was taken because the meter and test separators operate at nearly the same temperature and pressure.

Measurement data were logged continuously by ConocoPhillips and provided to MPM on a regular basis with regular start and stop times for the test periods. Reference data was not given to MPM – only the MPM data. ConocoPhillips then received average flows and time series during the well test periods from MPM. The MPM data was flashed to test separator conditions. The test separator data also was corrected for differences in liquid volume in the separator between the start and end of the test. Test separator water was measured as mass flow and manually converted to volume flow using water density for each well. Corrections were not made for water in the oil leg of the separator.

The test comprised 364 test hours based on 76 well tests from 13 wells, showing that the meter operated well within its specifications. The MPM meter still is in operation, delivering measurement data with the same quality as obtained during the test period without calibration or maintenance since its installation almost three years ago.

The subsea meter has gone through extensive operator-driven programs using stringent industry standards as a basis. The meter completed the DNV RP-203 qualification process and is qualified to meet API 6A and API 7D for up to 15,000 psi, 480°F (250°C), and water depth of 11,500 ft (3,500 m).
The meter was subjected to separate and equally rigorous blind testing at a number of industry test facilities and field applications to ensure it works as designed in real-life environments.

A full-scale 5-in. MPM subsea meter endured extensive testing at MPM's flow laboratory in Stavanger, Norway, followed by similar testing at Southwest Research Institute in San Antonio, Texas. During the process, nine oil companies sponsored the qualification of the MPM subsea meter. The self-calibrating functionalities were proven, and the specified accuracy was confirmed.