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.

A family of exciting new Electric Submersible Pump (ESP) technologies promises to radically improve the development economics of many oilfields and field extensions. This technology is particularly relevant to prospects in the range 5-100 million barrels reserves, which are located greater than 15 kilometres from existing platforms and often suffer uncertainties on reservoir performance (pressure, sweep, heterogeneities inflow performance etc.). Prospects in that category generally offer mediocre to inadequate economics or unacceptable risks of ‘downside’ potential. Platform development entails untenable capex exposure, whereas conventional subsea development (e.g. by gas lift) will result in very inferior production performance. The new technologies which ‘unlock’ the economics of such fields are: Viable subsea ESP technology is available now and will be field proven during 1994/95. Proven high reliability pump systems are now available, underwritten by performance contract. Bottom discharge pump systems offer powered ‘dump’ injection from an aquifer to the oil zone. (This is a particularly efficient way of achieving water injection and obviates the tremendous weight penalty of conventional water injection systems). Tandem pump versions of both conventional and bottom discharge systems offer much higher performance and assure long system life. Multiple pump completions may offer the prospect of the cost effective ‘complete for life’ subsea ESP well in both conventional and bottom discharge mode. These technologies offer superior technical and economic performance compared to existing, available methods, thus achieving enhanced development economics more robust to reservoir performance uncertainty.