Abstract

The history of the development of the Mardie Greensand reservoir at Thevenard Island illustrates the successful integration of subsurface modelling disciplines to enable the development and optimisation of a previously discarded hydrocarbon bearing zone. This has added 20–30 MMstb of Proved Reserves to the Thevenard Island asset. In particular, the use of G2-GOCAD modelling to generate a geostatistically populated grid proved invaluable in incorporating the heterogeneity of the reservoir. Formation evaluation modelling work contributed to the understanding of the reservoir petrophysics and better hydrocarbon identification from logs. Seismic EDGE (Enhancement & Detection of Geological Events) processing allowed the stratigraphic boundaries of the reservoir to be more accurately defined. Other seismic analyses have suggested that a northern extension to the field exists. The Chevron proprietary reservoir simulator, CHEARS, was used to model the reservoir and has also provided evidence for a northern extension to the field. The model has also been used to assess the value of infill well locations, and most importantly, the potential value of secondary recovery mechanisms such as water or gas injection. Finally, horizontal drilling technology and innovative geosteering techniques have contributed to the successful drilling of a number of horizontal, sinusoidal producing oil wells. Recently, the Mardie Greensand reservoir at the near by Cowle oilfield was exploited as a result of an integrated effort using the knowledge gained at Saladin.

Introduction

The Saladin field lies in 12 metres of water immediately adjacent to Thevenard Island in the Carnarvon Basin in Western Australia (Fig.1). The Saladin Mardie Greensand reservoir is a highly heterogeneous 10–100 mD glauconitic sandstone reservoir bearing a 49° API crude. The Mardie Greensand was, until recently, not considered to be a commercial pay-zone due to high water saturations and low resistivity response. However, horizontal wells have produced at rates up to 4,000 bopd of dry oil. Currently, nine horizontal sinusoidal wells are producing a total of 9,000 bopd, and three crestal vertical gas injection wells are injecting a total of 6 MMscfd. Gas injection is the current method of secondary recovery, although a water injection scheme is currently being proposed.

The Saladin Barrow Group reservoir was discovered in 1985 with the drilling of Saladin-1. This reservoir contained 100 MMstb of 49° API crude oil which flowed at individual vertical well rates of up to 15,000 bopd through a 1–20 Darcy reservoir supported by a very active aquifer drive. The Saladin Barrow Group reservoir was developed via seven vertical or deviated wells, three from Thevenard Island and four from offshore platforms. Production began in 1989 at rates near 50,000 bopd but by 1994 had declined to less than 10,000 bopd. At this point, Saladin-1, a watered-out Barrow Group producer, was recompleted to the immediately over-lying Mardie Greens and reservoir and was tested at 300 bopd. This was a surprising result given that the Mardie reservoir had previously been considered as non-pay due to intrepreted poor reservoir development and high interpreted water saturations. Saladin-1 disproved this theory, and further modelling indicated that a horizontal well through the Mardie may produce at rates up to 3000 bopd. Saladin-11 was subsequently drilled from Thevenard Island and proved to be successful (Fig.2). Several more wells were drilled from Thevenard Island and the existing offshore platforms resulting in production from the Mardie Greens and increasing to over 10,000 bopd. (Fig.3)

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