Pressure drop and stability characteristics of the flow in subsea flowlines are important to the proper operation of offshore platforms, and they depend intimately on the flow regimes that occur. Air-oil-water three phase flows in simultaneous horizontal and vertical pipe orientation are presented. Fast-sampling (250 Hz) gamma densitometer units were installed at the top of the 50.8mm diameter, 11m high vertical riser and horizontally near the riser base in the Cranfield University multiphase flow test facility. Gamma radiation attenuation data were collected from the caesium-137 radioisotope-based densitometer for a range of air-oil- water flow mixtures spanning the facility's delivery range. Examination of the gamma densitometer signal response revealed the presence of quasi-periodic waveforms in the time-varying multiphase flow densities. The probability mass function (PMF) characteristics predict the flow in the horizontal flow loop as bubbly, slug and wave flows while the vertical riser flow regimes were bubble, slug and churn. Flow pattern maps were then developed based on these PMF plots for both horizontal and vertical pipe orientation. The effect of upstream conditions on the vertical riser flow behaviour was also investigated via two different air inlet configurations:
upstream flowline mixing and
riser base injection.
No significant difference exist in flow behaviour at low superficial air-liquid velocities for both configurations, but at higher superficial air-liquid velocities, the intermittent flow behaviour due to hydrodynamic slugging in flowline influences the riser flow pattern characteristics, thus controlling the riser dynamics.
Multiphase metering is an exciting solution to the growing production measurement issues in the petroleum industry. Oil and gas production operations is occurring in more remote locations and deeper water depths (e.g. BP's PSVM Block-31, offshore Angola is located in water depth of 2000m; also the Great White, Silvertip and Tobago developments in the Gulf of Mexico are in water depths ranging from 2360 to 2940m, [Letton et al, 2010]), and with increasing tieback distances, calling traditional measurement employing three phase separator well testing into question. Moreover, new oil and gas developments commingled with existing infrastructures leads to various royalty payment requirements and further complicate the allocation process. These issues, coupled with widening operating envelope and improve measurement quality, is driving the development of multiphase meters to realize their full potential for reservoir monitoring, flow assurance calculations, production optimization, and reservoir engineering analysis [Kelner, 2009], in addition to their traditional areas of application such as well surveillance or monitoring, well testing, production allocation metering and fiscal or custody transfer measurements.
Multiphase meters today are vital to oil companies' field development and production plans. This is because over the past decade multiphase measurement technology has undergone a significant transformation such that the number of multiphase flow meters (MPFMs) installed globally has continued to increase [Joshi and Joshi, 2007]. Industry analysts predict that there will be 1,000 additional subsea multiphase meters deployed by 2015 [Ruden, 2010]. A number of factors are responsible for this rapid uptake of multiphase measurement technology. These are improved meter performances, decreases in meter costs, more compact meters enabling deployment of mobile systems, increases in oil prices, a wider assortment of operators [Blaney, 2008] and the development of compact subsea meters.
