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NEL: inaccurate meter calibration costs millions

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Hydrocarbon Engineering,

New research from NEL, the custodian of the UK’s National Flow Measurements Standards, has revealed that the use of live fluids to test and calibrate multiphase flowmeters increases measurement uncertainty by up to 7%. This inaccuracy could represent a potential financial mis-measurement of up to US$ 36 million per year for a well measured with a single multiphase meter.

While some favour the use of live fluids (i.e., natural gas, crude oil and brine), NEL’s laboratory research has proven they are less stable than substitute fluids (i.e., nitrogen, synthetic oils and synthetic brine), which deliver a more accurate result. It is for this reason that NEL has recently switched from using crude oil to refined oil as part of it multiphase flow loop meter testing.

Dr Norman Glen, Principal Consultant at NEL, said: “Proponents of live fluids argue that they are more representative of the conditions that the meter will encounter in service. However, our research has shown that due to the thermophysical properties of fluids, their use significantly increases uncertainty in calibration calculations. This means that inaccurate meters are being deployed in the field, potentially costing the industry and revenue authorities thousands of dollars every year.”

The use of substitute fluids, which provide a stable and well-characterised reference, is consistent with the approach recommended in the UK’s Department of Energy and Climate Change’s (DECC) Guidance Notes for Petroleum Measurement (Section 9.7), which makes specific mention of a preference for ‘model’ fluids to minimise additional uncertainties.

The research

A fluid stream was set up in NEL’s PPDS thermophysical properties software package to represent a typical set of conditions in the NEL multiphase test loop. A vapour/liquid/liquid flash calculation was undertaken, to determine the amounts of each phase present and the compositions of the phases. A calculation was also done for pure nitrogen, at the same temperature and pressure conditions, and the density values compared.

The calculated densities differed by less than 0.1%, confirming the assumption that the substitute fluid (nitrogen) remains in the gas phase and does not absorb liquids.

A similar set of calculations was performed with fluids representative of a live crude and natural gas. For this calculation a light crude with a specific gravity of 0.845 and a viscosity of 7.4 cSt at 100 °F was chosen. A representative natural gas mixture was also used (gas 3 from Table C.1 in Annex C of ISO 12213-2). In this case the density difference was 7%, due to partitioning of the hydrocarbon components between the vapour and liquid phases.

Additional calculations across a range of typical temperature and pressure conditions gave density differences of between 5 - 10%.

Whilst it may be possible to determine the gas phase composition in real-time by gas chromatography, the liquid phase composition can generally only be determined by sampling and off-line analysis. Even if this approach is used by laboratories using live fluids, there still remains the inherent uncertainties arising from the equations of state – all equations of state require additional parameters (binary interaction parameters) to account for non-ideal behaviour of real mixtures.

Variations to quantify the overall measurement uncertainties can be derived after the meter is installed in the field using PVT tests, coupled with the necessary fluid sampling and physical properties modelling. This second stage is a crucial part of the overall flow meter validation process.

Edited from source by Elizabeth Corner

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