Since the mid-1970s technology has enabled extraction of the UK’s oil and gas reserves in a cost-effective manner using subsea wells rather than individual platforms. In 2008, 43% of the UK’s oil and gas production was by subsea wells (The United Kingdom Offshore Oil and Gas Industry Association, 2010).

Centrica Energy performed an extended well test on a subsea high-pressure, high-temperature (HPHT) appraisal well in the North Sea and monitored the test using a permanently installed optical distributed temperature sensor (DTS) system. The high temperatures and pressures, together with a subsea installation, created specific challenges for monitoring the completion integrity and flow from the multizone reservoir during the well test.

In this paper the authors outline the deployment of the DTS system and present an interpretation of the acquired data. The completion was installed in one trip, with tubing-conveyed perforating (TCP) guns run at the bottom of the string. The firing of the guns, the completion integrity, and the fluid flow were monitored using a DTS optical fiber connected through the wellhead via an optical wet-connector and extending past the packer to the bottom of the guns. The same cable was used to operate a downhole electrical pressure gauge above the packer. Interpretation of the continuous temperature data enabled Centrica Energy to:

  • identify leaks at gas lift mandrels while pressure testing the production tubing during commissioning, allowing time saving decisions to be made on how to proceed with the installation.

  • check that all the perforating guns fired correctly to confirm that the whole reservoir was open to flow.

  • monitor the flow from different reservoir intervals over the 2-week well test to compare the flow profile from the reservoir to model predictions.

  • minimize QHSE risks associated with a well intervention.

You can access this article if you purchase or spend a download.