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Abstract The objectives of this study are to collect data of high-viscosity oil-gas flow in upward vertical pipe and assess the performance of existing mechanistic models developed based on low viscosity liquid experimental results. In this study, oil with viscosity between 0.1 and 0.5 Pa·s (100 and 500 cP) corresponding to temperatures from 37.8 to 15.6 °C (100 to 60 °F) and natural gas at 2.515 MPa (350 psig) pressure are used as the two phases. Superficial oil velocity lies in the range from 0.1 to 1.0 m/s and superficial gas velocity is in the range from 0.5 to 4.0 m/s. The internal diameter of the pipe is 52.5 mm (2.067 in). The experimental measurements include pressure gradient and liquid holdup. The flow pattern and slug characteristics are observed and the images are recorded with a high definition video system through a sapphire window. The experimental results are compared with the predictions of Zhang et al. (2003) unified model and other models, and the gaps are identified. Introduction Heavy oil together with extra heavy oil, bitumen and oil sands constitute 70% of oil resources worldwide. High viscosity liquids (0.1-10 Pa·s) produced in petroleum industry include heavy oil, oil produced at low temperatures close to the pour point such as in arctic or offshore environment and emulsions of oil and water. Production of such high viscosity fluids is a challenge. The conventional artificial lift systems must be modified (Dewan and Elfarr 1981; Szucs and Lim 2005). Pumps and gas lift are viable options. Disadvantages of pumps include the cost of the equipment, frequent (1-3 year) well intervention, low efficiency with high gas and sand productions. Gas lift is an attractive alternative and has already been used in Brazil, Canada, fomer Soviet Union, United States and Venezuela (Anderson and Stelzner 1962; Blann et al. 1999; Butler et al. 2000; Dou et al. 2007; Sakharov and Mokhov 2004; Targac et al. 2005; Trindade and Branco 2005). Field experience shows that high viscosity oils require 3-5 times more lifting gas flow rate than conventional oils. Mechanistic models developed for low-viscosity fluids may not be adequate to fully reflect the effect of high fluid viscosity on the performance of gas lift (Schmidt et al. 1984), e.g. the effect on the Taylor bubble behaviors (White and Beardmore 1962) including the slug length and the drift velocity (Gokcal et al. 2009; Sakharov and Mokhov 2004). High viscosity liquid-gas upward flows in vertical pipes are also of interest in chemical industry. In Schmidt et al., (2008) conducted measurements of void fraction using gamma-densitometer and flow pattern identification with photographs for gas-liquid vertical flow with liquid viscosity ranging 0.7-9.0 Pa·s. Pressure gradient was not reported in their experimental study. Bubble, slug, churn and annular flow patterns were observed. Significant disagreements of void fraction with the existing multiphase correlations were reported. McNeil and Stuart (2003) measured momentum flux, void fraction and pressure distribution at Mach number of 0.4 (mostly annular flow) for liquid viscosities 1-550 cP. Flow patterns were not observed visually and intermittent flow was expected when the load cell vibrated. Sakharov and Mokhov (2004) observed a new phenomenon of positive frictional pressure gradient in their experiments with high viscosity oils. This behavior appears at low superficial liquid velocity and this region increases with increase of viscosity. Field trials in Komi region showed applicability of gas lifting for high viscosity oils, although in some cases the gas injection caused the oil flow to stop. For industrial applications in Russia, Sakharov and Mokhov developed multiphase correlations applicable to the higher viscosity range. They also presented a new correlation for drift velocity with consideration of viscosity effect. From literature review very limited experimental results of high viscosity oil-gas flow in vertical pipes have been found (Table 1). In this study, a mineral oil with viscosities between 100 and 500 cP and Tulsa city natural gas at a pressure of 350 psig are used as the two phases. Superficial oil velocity ranges from 0.1 to 1.0 m/s, and superficial gas velocity from 0.5 to 4.0 m/s. The internal diameter of the pipe is 2.067 in. The experimental measurements include pressure gradient and liquid holdup. The flow pattern and slug characteristics are observed and the images are recorded with a high definition video system through a sapphire window. |
