Scott D. Mildren

Rotation of horizontal stresses in the Australian North West continental shelf due to the collision of the Indo-Australian and Eurasian Plates

There is a 40° rotation of regional maximum horizontal stress (σhmax) orientation between the western end of the Australian North West Continental Shelf (Carnarvon Basin) and its eastern end (Bonaparte Basin). A total of 625 borehole breakouts covering a cumulative length of 7.7 km in 42 wells in the Carnarvon Basin indicates a σhmax orientation of 090°–100°N. A total of 616 borehole breakouts over 6.8 km in 46 wells in the Bonaparte Basin indicates a σhmax orientation of 055°N–060°N. Together with extant data from the World Stress Map, these results indicate that regional σhmax orientation is 050°–060°N from New Guinea westward through the Bonaparte Basin to the Canning Basin (central North West Shelf). Between the Canning Basin and the Carnarvon Basin, σhmax rotates to 090°–100°N. The parallelism of σhmax orientation in the Bonaparte Basin to the Australia/Banda Arc collisional zone indicates that this collision is not generating significant net push. Rather, the 050°–060°N σhmax orientation of much of the northern Australian margin is probably controlled by the more mature New Guinea orogen to which it is approximately orthogonal. The observed rotation of σhmax can be explained solely by the focusing of the forces balancing ridge push along collisional segments of the northeastern boundary of the Indo-Australian Plate (such as the New Guinea orogen). Although not required to account for the observed stress rotation, a slab pull force from oceanic Indo-Australian Plate being subducted beneath the Sunda Arc cannot be dismissed.

FAST: A New Technique for Geomechanical Assessment of the Risk of Reactivation-related Breach of Fault Seals

Scott D. Mildren, Richard R. Hillis, Paul J. Lyon, Jeremy J. Meyer, David N. Dewhurst, Peter J. Boult

Stress partitioning and wellbore failure in the West Tuna Area, Gippsland Basin

Image logs from the deep intra-Latrobe and Golden Beach Subgroups of the West Tuna area in the Gippsland Basin reveal that wellbore failure is restricted to fast, cemented sandstone units and does not occur in interbedded shales. Triaxial testing and analysis of empirically derived, wireline-log based strength equations reveals uniaxial compressive strengths of 60 MPa in sandstones and 30 MPa in shales in the West Tuna area. Conventional analysis of wellbore failure assumes constant stresses in the shales and adjacent sandstones and that breakout is focused in the weaker units. We propose that the flat lying, strong, cemented sandstone units in the West Tuna area act as a stress-bearing framework within the present-day stress regime that is characterised by very high horizontal stresses (SHmax > Shmin = Sv). Stress focusing in strong sandstone units can result in high stress concentrations at the wellbore wall and account for the restriction of wellbore failure to the strong sandstone units. Finite element methods were used to investigate the stress distribution in horizontal, interbedded ‘strong’ sands and ‘weak’ shales subject to a high present-day stress state such as exists in the West Tuna area (SHmax > Sv ~ Shmirl). Modelling using the present-day stress tensor and estimated elastic properties for the sandstones and shales indicates that the present-day stress is ‘partitioned’ between ‘strong’ inter-bedded sandstones and ‘weaker’ shales, with high stress being focussed into the strong sandstones. The stress focusing causes borehole breakout in the sands despite their higher strength. Conversely, stresses are too low to generate wellbore failure in the weaker shales.

Stress deflections around salt diapirs in the Gulf of Mexico

Abstract Delta–deepwater fold–thrust belts are linked systems of extension and compression. Margin-parallel maximum horizontal stresses (extension) on the delta top are generated by gravitational collapse of accumulating sediment, and drive downdip margin-normal maximum horizontal stresses (compression) in the deepwater fold–thrust belt (or delta toe). This maximum horizontal stress rotation has been observed in a number of delta systems. Maximum horizontal stress orientations, determined from 32 petroleum wells in the Gulf of Mexico, are broadly margin-parallel on the delta top with a mean orientation of 060 and a standard deviation of 49°. However, several orientations show up to 60° deflection from the regional margin-parallel orientation. Three-dimensional (3D) seismic data from the Gulf of Mexico delta top demonstrate the presence of salt diapirs piercing the overlying deltaic sediments. These salt diapirs are adjacent to wells (within 500 m) that demonstrate deflected stress orientations. The maximum horizontal stresses are deflected to become parallel to the interface between the salt and sediment. Two cases are presented that account for the alignment of maximum horizontal stresses parallel to this interface: (1) the contrast between geomechanical properties of the deltaic sediments and adjacent salt diapirs; and (2) gravitational collapse of deltaic sediments down the flanks of salt diapirs.

Sealing by Shale Gouge and Subsequent Seal Breach by Reactivation: A Case Study of the Zema Prospect, Otway Basin

The Zema prospect, located in the Otway Basin of South Australia, hosts an interpreted 69-m (226-ft) paleohydrocarbon column. Two faults are significant to prospect integrity. The main prospect-bounding fault (Zema fault) shows a significant change in orientation along strike, with some parts of the fault trending northwest–southeast and other parts trending east–west, all at a consistent dip of about 70. The fault shows a complex splay and associated relay zone at its western tip. An overlying fault shows a similar northwest–southeast trend. Shale volume (Vshale) derived from the gamma-ray log was tied to seismic horizon data in order to model across-fault juxtaposition and shale gouge ratio on the Zema fault. Shale volumes of greater than 40% correspond with paleosol shale lithotypes identified in the core that are characterized by high mercury injection capillary entry pressures of 55 MPa (8000 psi), capable of supporting gas columns far beyond the structural spillpoint of the trap. Vshale values of 20–40% correspond to silty shale lithotypes characterized by mercury capillary entry pressures equivalent to gas column heights of less than 30 m (100 ft). Sands correspond with Vshale values of less than 20%. Juxtaposition modeling of the Pretty Hill reservoir interval that is displaced across the Zema fault against the Laira Formation seal demonstrates the existence of both sand-on-sand juxtaposition and sand-on-silty shale juxtaposition above the paleofree-water level. Hence, juxtaposition alone cannot explain the observed paleocolumn. It is therefore likely that fault damage processes on the fault plane were responsible for holding back the original 69-m (226-ft) column. Shale gouge ratio values show a gradual decrease from 32% at the top of the fault trap to less than 14% at the structural spillpoint. The fault damage zone is likely to consist of phyllosilicate framework rock types. Because the Zema trap was not filled to structural spillpoint, it is likely that the percentage of shale gouge in the fault zone not only provided the original sealing mechanism but also limited the original column height. This is supported by fault zone capillary entry pressures calculated from shale gouge ratio values, which indicate that the fault zone is only capable of supporting a maximum column height of 72 m (236 ft), just 3 m (10 ft) more than the interpreted column height of 69 m (226 ft). Geomechanical analysis shows that the northwest–southeast-trending parts of the faults are optimally orientated in the in-situ stress field for reactivation. A spontaneous potential (SP) anomaly in the Zema-1 well, which was recorded in a northwest–southeast-striking fault damage zone through the seal, confirms the existence of open, permeable fracture networks. These are likely to have been generated by recent reactivation that caused the breach and subsequent leakage of the entire original hydrocarbon column.

In situ stresses in the Southern Bonaparte Basin, Australia: Implications for first- and second-order controls on stress orientation

Four-arm dipmeter logs from six wells and a Formation MicroScanner (FMS) image log from one well in the southern Bonaparte Basin were interpreted for in situ stress indicators. Results of the analysis reveal a consistent NE-SW in situ maximum horizontal stress (σHmax) orientation (055°N). This orientation is parallel to the average σHmax determined in the northern Bonaparte Basin, the onshore Canning Basin, and in New Guinea. The data support the interpretation that the NE-SW σHmax orientation in the area reflects a first-order stress pattern controlled by plate boundary forces along the northeastern margin of the Indo-Australian Plate (IAP) and contradict the suggestion that NE-SW σHmax in the northern Bonaparte Basin is a second-order effect associated with boundary induced flexural stresses. Numerical modeling suggests that the divergence of σHmax from an orientation parallel to plate motion can be explained by the heterogeneous nature of the northeastern boundary of the IAP.