An experimental investigation was carried out to analyse the influence of coalescence behavior on drop size distributions in stirred liquid-liquid dispersions. An endoscope measurement technique was applied that allowed the determination of drop sizes even with high volumetric dispersed phase fractions j of up to 0.5. The influence of pH and addition of ions was studied by shaking and stirring experiments. For high coalescence rates, the results show self-similar drop size distributions independent of all other parameters. With low coalescence rates the Sauter diameter d 32 decreases and the distributions become narrower. When phase ratios were increased the common correlation d 32~( 1 + const. j) We ±0.6 did not lead to a reliable description of the mean drop sizes due to coalescence effects.

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Mechanisms of wave transformation in finite-depth water are investigated. The linear mechanisms examined are percolation, bottom motion, shoaling, and refraction. The nonlinear mechanisms examined are wave-wave interaction and bottom friction. New exact computations of the nonlinear transfer for finite-depth waves are presented for some directional wave spectra. These mechanisms are found to explain satisfactorily wave decay observations obtained at several sites with different bottom sediment properties. The decay rates at these sites are found to be dominated by different mechanisms which are determined by the bottom conditions. As an example, detailed calculations are presented for data obtained at the Jonswap site. where the complex wave number k is specified by 1jet Propulsion k=kr+ iki = w'• 1 + tanh (kh) •2 g tanh (kh) + •2 • is a complex function of water and mud properties as specified by Hsiao and Shemdin [1980] and Vg is the wave group velocity. Bottom scattering. This mechanism was explored by Long Paper number 80C0424.

The Rotliegend sandstone reservoir of Voelkersen (Northwest Germany) is a low permeability (kabs 2–4 mD), high pressure high temperature gas field (650 bar, 160°C). Its formation water is of high salinity (250 g/l) and characterised by its very high calcium content (= 40 g/l). The reservoir section of a partly depleted acceleration well was drilled using saturated water based sodium/potassium formate brine. For corrosion protection the pH value of the brine was adjusted to pH 10.5 using a bicarbonate/carbonate buffer. After gas production of 70 million m3(Vn) the production collapsed as a result of an unexpected build-up of calcium carbonate scale in the well bore area and the tubing. Two mechanisms have been identified as the cause of this scale formation. First the interaction of the caustic filtrate of the formate brine with the calcium rich formation water leading to a direct calcium carbonate precipitation. Second the enrichment of the formation water with bicarbonate by interaction with the caustic mud filtrate. This has resulted in calcium carbonate precipitation caused by the rise of the pH value of the water. The latter is resulting from decarbonisation caused by the pressure relief in the well bore area as a result of production. After subsequent mechanical and chemical scale removal, the gas production was even higher than at the initial state of production. However, having additionally produced 90 million m3(Vn) the production dropped again. This breakdown is attributable to an increase of bicarbonate in the formation water by a slow process of decomposition of formate left in the formation. This has resulted in subsequent scale formation following the decarbonisation process described above. To minimise the scaling potential of the formate brine while maintaining sufficient corrosion protection, careful adjustment of the pH value of the formate brine while drilling the reservoir section was implemented for successive wells. For already damaged wells several potential treatments have been identified and introduced, such as scale inhibition treatment integrated in hydraulic fracturing. Introduction The field Voelkersen, a Rotliegend sandstone natural gas reservoir in Northwest Germany between the cities of Bremen and Hanover, is a high pressure high temperature (HPHT) natural gas field (650 bar, 160°C). The first well in this field started production in September 1994. Recently a new acceleration well was drilled using formate brine with a low solid content to minimise differential sticking especially when partly depleted zones had to be drilled with a drill-in fluid that had to be overbalanced at the initial reservoir pressure of about 650 bar. This resulted in drilling the partly depleted reservoir target zones with an overbalance of about 250 bar. This high overbalance is due to the existence of rather small gas bearing layers in the last drilling section which are under initial reservoir pressure. A further reason for using formate brine was the high deviation of the borehole trajectory implying the risk of solid sacking. In this paper the reasons of the production breakdown caused by scale formation resulting from the interaction of the formate brine and the calcium rich formation water will be highlighted. Possible ways of treatment will be discussed as well as the adjustment of the formate brine to prevent such formation damages in future.

The Cavendish gas field is located off-shore in the Southern Gas Basin of the UK North Sea. The Westphalian and Namurian Fluvial Sandstones are at a depth of circa 11,500 ft (3,500 m). The wells showed an initial reservoir pressure of 6,100 psia (420 bara) and a temperature of 230 °F (110 °C). During gas production starting in 2007 the initial gas production rate of 60 to 70 MMscf/d per well decreased significantly after seven months of production. The condensate-gas-ratio was between 3.5 and 11.0 stb/MMscf for the two active producers. During a well workover at the end of 2010, down-hole solids and liquid samples were taken for analysis to identify possible formation damage processes. The solids were identified by x-ray diffraction as rust and scale, mainly carbonate scale. The liquids were characterized by gas chromatography as hydrocarbon condensate, with no trace of residual drilling mud. Two formation damage or productivity impairment mechanisms were identified; scaling and hydrocarbon banking.In order to restore productivity, the reservoir section of the two affected wells was milled and re-perforated. After this treatment their productivity was observed to increase significantly. A proactive scale inhibition treatment for the future was not regarded as necessary because all technical (non-formation) fluids were removed and the wells are not regarded as significantly self scaling. Alsothe reservoir pressure had decreased sufficiently to prevent any severe further retrograde hydrocarbon condensation in the wellbore area.