SPE Members


The completion design and perforation operations for the Everest and Lomond gas condensate fields incorporated several significant innovative features. These resulted in reduced rig time requirements, quicker access to sales gas and lower operations costs. Future benefits will include better well performance and reduced well workover and repair costs.


The Everest and Lomond Fields are located in the Central Graben area of the U.K. sector of the North Sea (see Fig 1). The reservoirs are Paleocene sandstones at an average depth of 8,500ft subsea. The reservoir fluid is a lean gas condensate. Gas is transported 255 miles to Teeside via the Central Area Transmission System (CATS) pipeline. Installation of this new line enabled the development of these 2 fields. Initial production from Everest and Lomond will be 300 MMSCFD. The 36 inch diameter CATS line has a capacity of over 1.6 BSCF per day of sweet or sour gas and this should encourage the development of several other fields in the Central North Sea.

The platforms are installed in 295 ft of water and each has 21 slots, although the first phase of development involves a total of only 16 wells - 9 at Everest and 7 at Lomond. An innovative, vertical-sided, tower-braced design was used for the jackets. This helped towards the construction objective of minimising jacket weight and deck area, ultimately producing significant savings in capital cost. As a consequence of this, the structure cannot accommodate a full sized platform rig. When a rig is required, a Giant Jack-Up must be brought in and the derrick package skidded off onto the platform. This, however, represents the ultimate in high cost completion and workover activity. The main challenge of the completion design was to find ways of lowering this cost.

Another challenge faced in completing the wells was the fast track development schedule of just over 36 months. Minimising the time required to complete the wells and bring them on production was a key objective on the critical path for the success of the total project.



Given the tight development schedule, it was obvious that the wells would need to be pre-drilled. This was carried out through subsea templates. The jackets were then set over these templates and the wells tied back to surface. Closer examination of the schedule revealed that there would probably not be sufficient time, between topside installation and the date of first gas sales, for the wells to be cleaned out after suspension, completed and perforated. The decision was then made to pre-complete the wells with all but the top 1000ft production tubing. The top-hole completion, including the sub-surface safety valve would be run during the tic-back operations.

This decision meant that our standard technique of perforating new development wells — TCP guns conveyed on the production tubing string — was no longer possible, as the tubing would be installed up to 2 years ahead of perforation.

P. 43^

This content is only available via PDF.
You can access this article if you purchase or spend a download.