Abstract

The Rita gas field was the first dual lateral well aimed at carboniferous reservoirs drilled in the UK Southern North Sea. This method enabled both the East and West fault segments of the field to be produced from the same upper well bore, thus reducing drilling costs and improving field economics. An invert emulsion drilling fluid was chosen for this field application due to the risk of shale instability over the long horizontal sections of each wellbore.

The West segment was drilled and suspended with a whipstock placed above the sand screen completion. The positioning of this whipstock would not allow for re-entry, making remediation of the West lateral impractical. A remediation treatment for this leg was required as the planned suspension fluid was an invert emulsion system that would be in contact with the completion screens and reservoir for more than a month whilst the East leg was drilled and completed. The chosen suspension fluid in the East leg removed the requirement for remediation with enhanced well productivity. This paper describes the design and testing of the reservoir drilling and suspension/completion fluids that were used on this multi-lateral project to minimise drilling time and maximise productivity.

Introduction

The well described in this paper was a complicated design and consisted of a dual lateral to produce gas from two unconnected reservoirs. The Rita well (44/22–12) was spudded in early July 2008. The first (West) leg of the well had a TD of over 17,000 ft with a 6" horizontal section of over 2,700 ft. After the lower completion was run in the first leg a whipstock was set to enable drilling of the second (East) leg. The East leg had a TD of 15,600 ft and a 6" horizontal section of over 2000 ft. The plan was to suspend the first leg for a period of time that might exceed 2 months to allow for the drilling of the second leg and the running and installing the novel completion.

This industry has experienced lower than expected production rates from wells which have been suspended for long periods with oil-based, solids-laden fluids before a clean up has been initiated. This raised the question of what type of fluid to leave below the whipstock, as re-entry to this leg for clean-up or well remediation was not economically feasible if production was lower than expected. Due to the diametrically opposed shape of the well, with long horizontal sections the drilling team was strongly in favour of using an oil-based reservoir drill in fluid (OBRDIF). This fluid would give a stable wellbore and provide a low friction co-efficient for drilling and running the completion assemblies.

Using OBRDIF would reduce the risk of hole instability and minimise non-productive time. However if OBRDIF was used in the drilling phase, it would mean that a solids-laden invert emulsion would be left in the hole when the first leg was suspended with the sand screens below the whipstock. This presented several risks. The fluid would require fine screening to prevent blocking of the completion equipment with drill solids. Also, there was a risk that the solid particles in the suspension fluid would agglomerate as the fluid remained static for an extended period. If agglomeration did occur, these solids would probably not pass through the mesh of the completion screens and could potentially reduce their conductance. The size and concentration of the solids in the suspension fluid were recognised as areas of concern that should be addressed to ensure maximum productivity of this well.

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