The workovers of subsea completed wells are expensive and time consuming as even the most routine tasks must be carried out by a semi-submersible. This paper describes the economic, safety and operational advantages which led to the development and successful first installation of 'through bore' subsea production trees.
The conventional wet subsea trees have proved to be very reliable over the past ten years of operation In the Argyll, Duncan and Innes fields, however past ten years of operation In the Argyll, Duncan and Innes fields, however the completion strings require pulling on the average about once every three to five years. The conventional subsea tree/tubing hanger set up design requires the tree to be tripped and a rig BOP stack run to pull the tubing. This operation is time consuming, very weather sensitive and leaves the well temporarily without a well control stack on the wellhead.
The 7 1/16" 'through bore' subsea tree was developed to minimize the tubing pulling workover time and several trees have been run successfully since the latter part of 1984. The time saving on a tubing pulling workover is three days. In addition, the design considerably reduces the hazards and equipment damage risks inherent in the conventional design. Hamilton Brothers and National Supply Company in Aberdeen designed the equipment which must be considered a new generation of subsea production trees.
Hamilton Brothers has operated the Argyll fields, a subsea system producing to a floating production facility, for over ten years. The producing to a floating production facility, for over ten years. The fields presently consist of 18 subsea wells including 2 water injectors and 5 gas lift wells. Well maintenance costs form a very high proportion of the total field operations costs, especially when compared to a platform developed field. Completions are designed to last the life of a field. In practice, however, a tubing pulling workover is required on average once per four years per well.
The reasons for workovers are similar to a platform or land well. Fourteen tubing pulling workovers have been performed over the past 5 years. The reasons, in order of frequency, have been:
Repair problems to the DHSV system.
Change out of the completion to include gas lift equipment.
Recompletion in another zone.