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 work-over 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.

  1. Scaling

    Carbonate scale was caused by the interaction of reservoir brine and the high concentration of carbonate ions in the high pH K-formate drilling fluid. Due to the comparatively long exposure times (ca. 16 days) and thermal degradation of the drilling fluid, hydrogen-carbonate ions were formed and because of the relatively high calcium content of the formation water and presence of ferroan dolomite as intergranular cement within the matrix, carbonate scale was precipitated.

  2. Hydrocarbon Banking

    Liquid hydrocarbons condensed as a result of the lean-retrograde gas condensate character of the reservoir fluids and reservoir pressure decreasing below the respective dew point pressures. This was confirmed by the interpretation of the PVT and fluid compositional analysis with computational software tools.

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.

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