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Published: Kem. Ind. 53 (4) (2004) 157–165
Paper reference number: KUI-02/2003
Paper type: Professional paper
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Properties and Generating Mechanism of Water-in-Crude Oil Emulsions in Deep Oil Wells

M. Tomić and Z. Krilov


During the initial production from several wells at oil field C in Southern Drava basin – Croatia, the oil production was reduced due to w/o emulsion generated somewhere downhole as indicated in produced fluid. A payzone in Well Cx was drilled using polymeric water base mud. After well completion the zone at depth 2746–2728 m (Bottom hole static temperature, BHST=145°C) was perforated. The well was unloaded and a very viscous bituminous like material was obtained at surface by swabbing. The continuous swabbing brought the well on sporadic production of oil and water with decreased flow rate. The samples of produced fluid were collected and analyzed in laboratory in order to find out the cause of flow rate reduction. Experiments were carried out in order to simulate possible conditions of emulsion generation downhole and to characterize and explain this process. Five kinds of tests were run: (1) emulsion generation tests, (2) emulsion type determination, (3) microscopy – investigating droplet size and shape, (4) emulsion stability tests, and (5) fluid viscosity measurements under the simulated bottom-to-wellhead flow conditions. Tests were caried out using samples of (1) crude oil and its distillation fractions, (b) synthetic formation water, (c) mud filtrate and (d) bentonite. Results of emulsion generation tests conducted at 82 °C demonstrated the existence of long term stable emulsions in most cases. During mixing period it has been noticed that the samples with aqueous phase content higher than 70% required more than double mixing speed (700 vs. 1500 rpm) for emulsification. The experiments done under reservoir temperature conditions (145 °C), proved the hypothesis that emulsion could be formed and remained stable near wellbore zone, in-situ. This finding has an extremely important impact in making decision for selecting appropriate methods of well and/or fluid treatment downhole, to increase oil production after breaking of emulsion in-situ. Considering emulsion type determination test results (using deionized water as inorganic solvent and diesel oil as an organic one) it may be concluded that in all cases except two samples the generated emulsions were water-in-oil (w/o) type. Even the emulsion samples with aqueous phase content as high as 90% appeared to be w/o type. Analysing the droplet size data it could be pointed out that in case of emulsions composed of crude oil and synthetic formation water the droplet size ranges from 1 to 20 μm. On the other hand, when bentonite was added the droplet size range was increased (4 to 80 μm). The mixing rate also influenced the droplet size. Mixing at about twice higher rate resulted in much smaller (1 to 7 μm) droplet size, which confirms the earlier reported results. Also, samples with lower pH value of aqueous phase demonstrated smaller droplet diameter (1 to 7 μm) than the ones having the same composition but pH higher than 7. Samples of emulsion, generated under high temperature conditions (145 °C), showed the same droplet size range as the ones, generated at 82 °C. Results of electrical stability (ES) measurement provided the data for correlation of ES with o/w ratio. Generally saying, evident is a tendency characterized in the way, that the decrease of the aqueous phase content increased the electrical stability of emulsion. Lowering the pH value of aqueous phase resulted in the tendency of getting higher ES values. This matches the findings about asphaltenes which make very stable rigid films around water phase droplets in a low pH environment. The study of viscosity change under simulated well production conditions demonstrated the oil mobility restriction. The most drastic viscosity increase was evidenced in the case of 50:50 o/w ratio (about ten times higher viscosity in comparison with sole crude oil at temperature 95 °C – half a way from perforations to the wellhead). Results of test indicate reduced fluid mobility due to emulsification. Photomicrographs, ES measurement and chemical analysis data, signify that particular crude generates a stable w/o emulsion under a relatively high oilwell reservoir temperature (145 °C). The contamination with bentonite particles strongly affects the emulsification process, increasing the emulsion stability and changing its type. Asphaltenes and polar organic molecules showed a dominant role in emulsification mechanism. The formation of studied hard to break emulsions in near wellbore zone as well as inside downhole tubulars, could strongly reduce the oil well productivity as demonstrated in lab simulation experiments.

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emulsion, water-in-crude oil, oil production