Abstract

The Shearwater and Elgin fields, operated by Shell UK and Total respectively, are high temperature and high pressure gas/condensate production fields located in the Central Graben area of the Central North Sea (Block 22/30) of the U.K. Continental Shelf, 220 kms east of Aberdeen. Shearwater is a platform development and produces rich gas-condensate from Fulmar and Pentland reservoirs at very high reservoir temperatures (up to 190°C), initial pressures (up to 1060 bar) and salinity (around 250,000 mgl[-1]). The risk of scale deposition - primarily CaCO[3] and NaCl - was recognised early in the development phase, and whilst the latter was only predicted for the topsides, CaCO[3] was expected throughout the production system. Both have been observed topsides and there is increasing evidence that scale (inferred to be CaCO[3]) is also depositing down-hole.

The Elgin field lies in a structurally complex area nearly six kilometres below the seabed, where the pressure is over 1100 bar, the reservoir temperature around 200ºC, and brine salinities up to 300,000 mgl-1. Calcium carbonate scale deposition has been experienced downhole in Well G6.

As the CaCO[3] scaling potential had been predicted and observed in both fields, it became clear that downhole scaling would need to be controlled by applying inhibitor squeezes. Separate laboratory studies were undertaken to identify suitable scale inhibitors that were thermally stable and compatible under the harsh HP/HT conditions encountered in each field. Since non-aqueous scale inhibitors were not considered to be applicable under these HP/HT, high-salinity conditions, aqueous-based inhibitors were selected for squeeze application. However, it was essential to ensure that any treatment package did not induce significant near-wellbore damage, e.g. due to the ingress of large amounts of aqueous fluids into dry hydrocarbon-producing zones.

A significant difference between the two fields described here was the phase behaviour of the hydrocarbon fluids in the near-wellbore during the squeeze treatments. In Shearwater, condensate drop-out was expected during a squeeze operation, which implied that back-production of this liquid would be required to ensure recovery of gas productivity. For the Elgin reservoirs, however, the hydrocarbons in the near wellbore area were expected to remain as dry gas during a squeeze treatment. A series of novel core flood experiments were therefore conducted to examine the return characteristics of the fluids present in the different reservoirs for different squeeze application strategies. For the Shearwater reservoir this involved the design and evaluation of a hybrid aqueous/non-aqueous treatment that fulfils all requirements including causing negligible formation damage when applied in Shearwater cores. For the Elgin conditions a conventional fully aqueous package was examined.

This paper therefore examines the implications associated with the fluid in place and the associated PVT behaviour of downhole fluids during the design of a squeeze treatment package for application on HP/HT gas condensate fields.

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