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Integration Of Structural, Stress, And Seismic Data To Define Secondary Permeability Networks Through Deep Cemented Sediments In The Northern Perth Basin

Bailey, Adam H. E.

Geoscience Honours Degree, 2011

University of Adelaide


Understanding natural fracture networks has been increasingly recognised as an important factor for the prospectivity of a geothermal play, as they commonly exert a primary control over permeability at depth. Low primary porosity and permeability values have been initially recorded in the Northern Perth Basin due to silica rich groundwater infiltration and consequent quartz cementation. The onshore Northern Perth Basin provides a good example of how fracture stimulation, and subsequent enhancement of the structural permeability, during hydrocarbon production can enhance flow rate from original tight gas reservoirs.

Geothermal energy prospectivity in the region will therefore depend heavily on similar engineering techniques and/or on the presence of secondary permeability due to interconnected natural fractures. The existence and extent of these natural fractures has been verified in this study through an integrated analysis of geophysical logs (including wellbore image logs), wells tests, and 3D seismic data.

Wellbore image logs from 11 petroleum wells in the Northern Perth Basin have been used to identify borehole failure (such as borehole breakout and drilling-induced tensile fractures) to give a present day maximum horizontal stress orientation of N076°E (with an s.d. of 13°). Density logs and well tests from 13 petroleum wells have been used to constrain the present day stress magnitudes, giving a transitional strike-slip faulting to reverse faulting stress regime in the Northern Perth Basin when considered alongside previous studies and neotectonic evidence.

870 fractures have been identified in image logs from 13 petroleum wells in the Northern Perth Basin, striking approximately N-S and NW-SE. Fractures aligned in the present day stress field are optimally oriented for reactivation, and are hence likely to be hydraulically conductive. Electrically resistive and conductive natural fractures were identified on the wellbore image logs. Resistive fractures are considered to be cemented with electrically resistive cement (such as quartz or calcite) and thus closed to fluid-flow. Conductive fractures are considered herein to be uncemented and open to fluid-flow, and are thus important to geothermal exploration. Fracture susceptibility diagrams constructed for the identified fractures illustrate that the conductive fractures are optimally oriented for reactivation in the present day strike-slip fault to reverse fault stress regime. This is reinforced by the correlation of drilling fluid loss and conductive natural fractures in three wells in the Northern Perth Basin.

In order to gain an understanding of the extent and interconnectedness of these fractures it was necessary to look at more regional data such as 3D seismic surveys. However, fault and fracture networks observed in image logs generally lie well below seismic amplitude resolution, making them difficult to observe directly on amplitude data. However, seismic attributes can be calculated to provide some information on sub-seismic scale structural and stratigraphic features. Using a 3D seismic cube acquired over the Dongara North gas field, attribute maps of complex multi-trace dip steered coherency and most positive curvature were used to document the presence of natural fractures and to best constrain the likely extent of the fracture network. The resulting fracture network model displays relatively good connectivity, which is likely to extend over much of the basin. These optimally oriented fractures therefore are likely to form a secondary permeability network throughout the cemented sediments of the Northern Perth Basin, offering potential deep fluid flow conduits that may be exploited for the production of geothermal energy.

Australian School of Petroleum



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