Innovation and risk management in a small subsea-tieback: Arkwright Field, Central North Sea, UK

Abstract

Arkwright is a 50 × 10 6 BBL oil field located within a single Forties Sandstone Member turbidite ‘channel’ system. Arkwright was discovered in 1990 and developed in 1996. Earlier start-up was precluded by reservoir risk and lack of export pipeline capacity. Reservoir definition improved after acquiring a 3D survey and applying imaging and attribute studies. This, combined with subsurface analogue, core, and carbon, oxygen and strontium isotopic studies, improved understanding of reservoir architecture and connectivity. Geostatistical techniques were used to quantify the STOIIP. The main risks identified were the absence of aquifer support, and possible vertical and lateral baffling. As these could not be tested by appraisal drilling it was decided to commence development. Low-cost, two-well development options were considered and rejected because of the subsurface risk. Without guaranteed aquifer support, the productivity from early sub-bubble point flow would be lost waiting for injection support to be added. Risk-weighting highlighted the advantage of initial expenditure to safeguard the project, and so a third initial production well was planned, in a location suitable for conversion to injection. Predicted rates were increased and the impact of lateral baffling minimized by drilling deviated producers on opposite sides of the structure, and not reusing the discovery well. Costs were reduced by using a drilling centre outside the field. The perforation strategy ensures drainage above and below potentially sealing abandonment shales, and facilitates future zonal isolation. Communication within the reservoir was tested at start-up with an interference test.