The Influence of Depositional Environment on Reservoir Quality of the Macedon Member, Exmouth Sub basin, Western Australia
Honours Degree 2002
University of Adelaide
The Berriasian Macedon Member of the Lower Barrow Group forms a key reservoir in the Exmouth Sub-basin. Recent discoveries such as Macedon/Pyrenees, Enfield and Laverda have all intersected the Macedon Member. Hence the Macedon Member is a highly prospective play in the Exmouth Sub-basin.
Plotting porosity and permeability trends with respect to facies shows that subtle changes in facies type and lithology have a significant effect on porosity and permeability. Generally sand rich facies such as vertically amalgamating basin floor lobes, upper shoreface and channel facies display the highest porosities and permeabilities and form the best reservoirs in the Macedon Member. The clay and mud-rich shelf mud facies exhibits the lowest porosity and permeability and forms an ideal intra-formational seal.
Statistical analysis of porosity and permeability data shows that the basin floor lobe facies forms the best reservoirs, with mean porosity of 27.5% and mean permeability of approximately 2000 mD. Unconfined channels also form good reservoirs with mean porosity of 26% and permeability of approximately 1000 mD, followed by the upper shoreface facies, matrix supported mass flows and channels within incised canyons.
Where the relationship between porosity and permeability for a single facies is similar for different wells, it is possible to estimate reservoir quality from seismic data where individual facies have been identified. The upper shoreface facies of Enfield-1 and Enfield-2 can be seen in seismic data, and the similarity between porosity and permeability trends suggests that another well intersecting this facies would have similar porosity and permeability. The basin floor lobe facies intersected in Batavus-1, Macedon 3 and Macedon-4 also have similar porosities and permeabilities. Hence where a basin floor lobe is identified in seismic data, an estimate of reservoir quality could be gained from the porosity versus permeability trend. In general facies that are characterized by homogeneous sands show correlation between porosity and permeability trends for different wells, where sediment is inhomogeneous, such as with mass flows, porosity and permeability varies depending on percentage of shale clasts. In this case porosity and permeability is different for each individual flow. The use of porosity and permeability relationships if combined with other reservoir quality estimation techniques has potential in minimizing risk in exploration.