p.2 ~ Reservoir conditions, flow regimes challenge measurement accuracy-full

Displaying 2/2 Page 1, 2
View Article as Single page

Salinity and conductivity

Measuring water conductivity and salinity also is increasingly important in the operation of multi-phase meters. Salinity is viewed as a key operational parameter for reservoir management and flow assurance with salinity measurements telling the reservoir engineer whether formation water is entering the flow, and helping the process engineer adjust injection rates of scale and corrosion inhibitors.

In water continuous flow, multi-phase meters are also dependent on an input of water conductivity/salinity values to achieve their correct performance specifications. While variations in water salinity have no influence on the Roxar multi-phase meter's measurements in process conditions at less than ~60 water/liquid ratio WLR (i.e. oil continuous flows), at higher water cuts the water conductivity is an important input value to any multi-phase meter with significant sensitivity coefficients.

For example, with a GVF at 80%, WLR at 60%, and a water conductivity change at +1% rel, the additional uncertainty would be a liquid rate (% rel) at -0.1 % and WLR (% abs) at +0.6%.

Taking these influence quantities into account, Emerson has developed two dedicated salinity/conductivity sensors for operation in multi-phase and wet gas flow and that enable absolute measurements of produced water salinity. The wet gas probe measures salinity in wet gas and high GVFs and the multi-phase probe measures salinity in water continuous multi-phase flow.

The dedicated salinity sensor for multi-phase flow is based on microwave transmissions and can operate in three-phase gas-liquid flows. The sensor measures the effect of the flow on the propagation of the microwave signal in the volume between three probes, with the salinity of the water phase and the local water/liquid ratio then able to be deduced. The result is a better quantification of uncertainty and improved meter measurements.

Handling MEG injection

Operators face threats to flow assurance and multi-phase meter performance from hydrates – the crystals that are formed in high-pressure and low-temperature gas flows where water and natural gas are present.

The growth in deepwater wells with high GVFs, high pressures, and low temperatures increase this threat, with gas hydrates the most common form of downhole blockage. For multi-phase flows, issues include formation of waxes, hydrates and scales; restrictions and blockages; and corrosion and damage of equipment.

While thermodynamic inhibitors such as methanol and ethylene glycol (MEG) are currently the most effective ways to prevent hydrates, they add measurement challenges of their own for multi-phase meters.

MEG is measured as water by the electrical impedance sensor system of the multi-phase meter. The densities of these fluids are lower than water, so the density of the mixed flow can be reduced and, if a considerable amount of MEG is injected, could influence measurements from the gamma system.

To meet this circumstance, either subtract the MEG injection rate from the reported water rate from the multi-phase meter or provide water density input into the multi-phase meter. In this way, measurements can be updated that account for the combined density of the expected water production and MEG/Methanol injection, thereby removing the influence quantity effect on the gamma system.


In all these and other cases of influence quantities, it is important to understand that different multi-phase metering technologies may be affected differently. Understanding influence quantities, sensitive coefficients, and how they are being addressed, should be key elements of the selection process.

Displaying 2/2 Page 1, 2
View Article as Single page

More in Home