Abstract

The Stybarrow Field is a moderate size biodegraded oil accumulation reservoired in early Cretaceous slope turbidite sandstones of the Macedon Formation in the Exmouth Sub-Basin offshore Western Australia. Excellent quality 3D seismic has enabled attribute mapping and probabilistic seismic inversion to be used to both estimate the net sand distribution of the reservoir and facilitate optimal well placement. The reservoir comprises excellent quality, but poorly consolidated, sand rich turbidites up to 20m thick. The field lies in >800m of water and has been developed with four near horizontal gravel packed production wells connected to an FPSO via sub sea trees and flowlines.

Water injection is required for pressure maintenance and produced gas is re-injected into the nearby Eskdale oil & gas field, the oil leg of which is produced via a single horizontal well. Pressure support is required from field start-up due to lack of aquifer support. Horizontal production wells with high productivity indices are required for optimal drainage. Downhole sand control is provided by a combination of open-hole gravel packs and sand screens.

Key subsurface challenges were faced in the development of the relatively thin reservoir containing biodegraded 22° API oil with little or no aquifer support. Lateral reservoir variations have important implications for connectivity and therefore the optimal drainage of such fields.

The Stybarrow project involves a nine well subsea development and a double hulled FPSO, the Stybarrow Venture, with capacity of approximately 80,000 barrels of oil a day. Oil came on stream in November 2007 and nameplate production was reached within weeks of first oil. The Stybarrow and Eskdale fields which make up the project have estimated recoverable oil reserves of 60 to 90 million barrels and estimated field life is 10 years.

This paper documents a multidisciplinary approach applied during the appraisal, development and early production life of the field. Static and dynamic data on a variety of scales (i.e. seismic, well data, bed boundary resistivity modeling, inter-well interference testing and early production performance) have been integrated into detailed 3D geological models, which have enabled a greater understanding of reservoir connectivity, as well as a better estimation of ultimate oil recovery.

INTRODUCTION

The Stybarrow oilfield is located in Production License WA-32-L, some 56km northwest of Exmouth, offshore Western Australia (Figure 1). Water depth over the field is approximately 825m. The field lies near the southern margin of the Exmouth sub-basin within the overall Carnarvon Basin. Although the potential of the Stybarrow structure had been recognised on 2D seismic data, it was not high graded for drilling until seismic amplitude anomalies conforming approximately to structure were observed in a subsequent 3D seismic dataset acquired in 2000. The 3D seismic data indicated the prospect had many similarities to the nearby Laverda and Enfield discoveries.

Biodegraded (22° API) oil is trapped in Early Cretaceous, Berriasian age turbidite and debris flow sandstones deposited on a passive margin slope. The Stybarrow structure comprises a NE-SW trending tilted fault block forming a terrace within the westward plunging Ningaloo Arch (Figure 2a). The intersection of NNE/NE and E-W trending normal faults establish an elongate, triangular trap with dip closure to the east and structure dip of about 5 degrees. Top, base and bounding-fault seals are provided by claystones and siltstones of the overlying Muiron Member of the Barrow Group and mudstones of the underlying Dupuy Formation. Oil is sourced from claystones of the Dingo Formation.

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