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The continental margin of West Africa formed as result of the south-to-north rifting of Gondwana and the progressive separation of the South American and African continents. This margin has enjoyed a rich and varied exploration history and, in the 70 years or so since the first significant exploration began in the onshore area, the margin has emerged as a significant hydrocarbon-producing region. The amalgamation of hydrocarbon exploration approaches and imaginative ideas, leveraged with modern technologies, is yielding significant scientific and eco

Mechanical damage (e.g. faults and fractures) related to tectonic forces and/or variations in formation pore pressures may enable the leakage of fluids through otherwise effective seal rocks. Characterisation of faults and fractures within seals is therefore essential for the assessment of long-term trap integrity in potential CO2 storage sites. 3D seismic reflection data are used to describe a previously unrecognised network of extensive, small Miocene-age faults with displacement of generally

Naturally occurring fractures were remotely detected in a 3-D seismic volume from the Penola Trough in South Australia's Otway Basin and validated through an integrated approach. Identified in image logs are 508 fractures and 523 stress indicators, showing maximum horizontal stress orientation in the Penola Trough is 127°N. Two fracture types were identified: (1) 268 electrically conductive (potentially open to fluid flow) fractures with mean NW-SE strikes and (2) 239 electrically resistive (closed to fluid flow) fractures with mean E-W strikes. Core from Jacaranda Ridge-1 shows that open fractures are rarer than what image logs indicate, due to the presence of fracture-filling siderite, an electrically conductive cement which may cause fractures to appear hydraulically conductive in image logs. The majority of fractures detected is favorably oriented for reactivation under in situ stresses, although it is demonstrated that fracture fills primarily control which fractures are open. Seismic attributes calculated from the 3-D Balnaves/Haselgrove survey are mapped to the Pretty Hill Formation to enhance observations of structural fabrics, showing linear discontinuities likely representing faults and fractures. Discontinuity orientations are consistent with natural fracture orientations identified in image logs, striking E-W and NW-SE, limited to zones around larger faults. However, it is unlikely that a large proportion of these fractures are open given observations of core and image logs, limiting possible fracture connectivity and therefore significant secondary permeability in the Penola Trough. The integrated methodology presented herein provides an effective workflow for remote detection of subsurface fractures and determining if electrically conductive fractures are also hydraulically conductive.

This paper presents a 3D geomechanical modelling study of the Iona gas storage facility in the state of Victoria, Australia. The results provide important information pertaining to gas storage, which can then be used to understand certain geomechanical aspects of CO2 storage. A key finding in this paper is that significant changes to the horizontal stress magnitudes are imparted by changes to the fluid pressure due to gas injection or withdrawal. This effect, known as the reservoir stress path, significantly influences fault stability by counteracting the changes to effective stress. In the case of Iona, pressurisation of the field results in a stress path which is parallel to the failure criterion rather than towards it, as would be expected in a classical treatment which does not incorporate complex poro-elastic effects. Another output of interest relates to reservoir deformation, which would be manifested at the ground surface as heave or subsidence. During periods of peak gas withdrawal and injection, surface ground movement is predicted to be on the order of −9 mm and +2.5 mm, respectively. These numbers are similar to the surface deformation observed at the In Salah CO2 injection project, but much smaller than the subsidence observed in some producing hydrocarbon fields.

The Late Cretaceous Ceduna Delta is the largest deltaic system on the Australian continent, yet its source is unknown. Apatite fission-track data reveal widespread Late Cretaceous exhumation across the southern Australian margin. New detrital zircon analysis of 786 grains from the Gnarlyknots-1 well, which penetrated the offshore delta top, show that the upper part of the delta (Santonian–Maastrichtian) was sourced largely from recycled Permian to Early Cretaceous cover and underlying basement eroded from the margin, proximal to the basin. This challenges the widely accepted model involving distal provenance of >2000 km from the eastern margin of Australia. Supplementary material The 2D seismic reflection data, results for detrital zircon LA-ICP-MS and zircon fission-track analyses, including the LA-ICP-MS method, and a list of sample intervals and ages are available at www.geolsoc.org.uk/SUP18582.

The successful commercial scale deployment of carbon capture and storage (CCS) requires assurance of the confinement of the injected CO 2 at each potential storage site. The critical elements of the confinement of CO 2 are the caprock overlying the storage formation, and any faults or fractures which occur within the caprock. The most significant aspect of containment is the seal potential of the caprock, defined as the seal capacity, seal geometry and seal integrity. The seal capacity refers to the CO 2 column height that the caprock can retain before capillary forces allow the migration of the CO 2 into and possibly through the caprock. Determination of capacity is achieved primarily through petrophysical analyses such as mercury injection capillary pressure (MICP) tests. For storage in depleted fields, assessments of seal capacity can be made from empirical observations of actual hydrocarbon column heights and converting these to CO 2 physical properties (density, temperature, pressure). Where these data sources are unavailable, the use of analogs can be a viable alternative. Seal geometry refers to the thickness and lateral extent of the caprock. The caprock must have sufficient lateral extent to cover whatever structural, stratigraphic or hydrodynamic storage reservoir in which the CO 2 is trapped. In addition, its thickness should exceed the throw of any faults that cut so as to maintain an effective barrier despite faults through it. Seal geometry is evaluated through well data (stratigraphic, sedimentological and wireline log analyses) and seismic surveys, which are pre-requisites to any viable storage project. Seal integrity refers to the geomechanical properties of the caprock. These properties are controlled by caprock mineralogy, regional and local stress fields as well as any stress changes induced by injection or withdrawal of water or CO 2 . The modification of the stress field within a storage formation during and after injection of CO 2 can lead to reservoir and caprock mechanical failure. This failure can result in the generation of new faults and fractures, reactivation of existing faults and/or bedding parallel slip. The key parameters determining whether faults might act as conduits or as seals are the juxtaposition relationships of rocks on either side of a fault plane, the properties of the fault zone itself or the reactivation potential of the fault. The greatest likelihood of fluid migration up faults is during or immediately after reactivation. Thus, the mere existence of faults does not automatically rule out a site for geological storage of carbon dioxide. On the contrary, sealing faults commonly trap hydrocarbons and compartmentalize oil and gas reservoirs and could also form suitable confining barriers at CO 2 storage sites. Seal capacity, geometry and integrity interpretations must be tempered by the potential geochemical reactions between fluids and rocks and injected CO 2 as well as by the hydrodynamic environment above and below the seal which may modify the calculated pressure regimes.

International audience; The Venezuelan Andes form a N50 degrees E-trending mountain belt extending from the Colombian border in the SW to the Caribbean Sea in the NE. The belt began to rise since the Middle Miocene in response to the E-W collision between the Maracaibo block to the NW and the Guyana shield belonging to South America to the SE. This oblique collision led to strain partitioning with (1) shortening along opposite-vergent thrust fronts, (2) right-lateral slip along the Bocono fault crossing the belt more or less along-strike and (3) crustal escape of the Trujillo block moving towards the NE in between the Bocono fault and the N-S-striking left-lateral Valera fault. The geology of the Venezuelan Andes is well described at the surface, but its structure at depth remains hypothetic. We investigated the deep geometry of the Merida Andes by a 3D model newly developed from geological and geophysical data. The 3D fault model is restricted to the crust and is mainly based on the surface data of outcropping fault traces. The final model reveals the orogenic float concept where the mountain belt is decoupled from its underlying lithosphere over a horizontal decollement located either at the upper/lower crust boundary. The reconstruction of the Bocono and Valera faults results in a 3D shape of the Trujillo block, which floats over a mid-crustal decollement horizon emerging at the Bocono-Valera triple junction. Motion of the Trujillo block is accompanied by a widespread extension towards the NE accommodated by normal faults with listric geometries such as for the Motatan. Momboy and Tuname faults. Extension is explained by the gravitational spreading of the upper crust during the escape process.

The Ceduna Sub-basin is located within the Bight Basin on the Australian southern margin. Recent structural analysis using newly acquired two-dimensional (2D) and three-dimensional (3D) seismic data demonstrates two Late Cretaceous delta–deepwater fold–thrust belts (DDWFTBs), which are overlain by Cenozoic sediments. The present-day normal fault stress regime identified in the Bight Basin indicates that the maximum horizontal stress ( S Hmax ) is margin parallel; Andersonain faulting theory therefore suggests the delta-top extensional faults are oriented favourably for reactivation. A breached hydrocarbon trap encountered in the Jerboa-1 well demonstrates this fault reactivation. Faults interpreted from 3D seismic data were modelled using the Poly3D © geomechanical code to determine the risk of reactivation. Results indicate delta-top extensional faults that dip 40–70° are at moderate–high risk of reactivation, while variations in the orientation of the fault planes results in an increased risk of reactivation. Two pulses of inversion are identified in the Ceduna Sub-basin and correlate with the onset of rifting and fault reactivation in the Santonian. We propose a ridge-push mechanism for this stress which selectively reactivates extensional faults on the delta-top, forming inversion anticlines that are prospective for hydrocarbon exploration.

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 498. However, several orientations show up to 608 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. In many regions worldwide sH orientations are parallel or subparallel to absolute plate velocity vectors and ridge torques, for example, North America, South America and Western Europe (Richardson 1992; Zoback 1992). First-order intraplate stress patterns (wavelengths .1000 km) are therefore a result of large-scale plate boundary forces (e.g. ridge push, slab pull). The stress field generated by plate boundary forces are superimposed on major intra-plate sources of stress (gravitational forces imparted by mountain belts; lithospheric flexure) to generate the second-order stress pattern (wavelengths 100–500 km; Zoback 1992). However, recent years has seen significant advance in the understanding of short-wavelength (,100 km) third-order stress fields observed at the reservoir-, fieldand basin-scale in sedimentary basins generated by local effects (e.g. topography, sediment loading, glacial rebound, elastic dislocation from large faults, overpressure generation, buckling, asperities on fault planes and lateral density contrasts; Bell 1996; Tingay et al. 2006; Heidbach et al. 2007; MacDonald et al. 2012). It is the relative magnitudes of the sources of stress that define the dominant stress regime in a given region (Zoback 1992; Bell 1996; Tingay et al. 2006). For example, a local stress source may induce large differential stresses that override the regional (far-field) stress source so that third-order stress patterns dominate in the area (e.g. Sonder 1990; Bell 1996; King et al. 2010a). Alternatively, a local stress source with low differential stresses may still affect stress orientations in regions where a layer with low shear strength (e.g. a detachment at the base of a delta system or a salt horizon) prevents the transfer of regional far-field stresses into layers where measurements are taken (Tingay et al. 2011; Bell 1996; King et al. 2010b). Delta–deepwater fold–thrust belts (DDWFTBs) are linked systems of extension and compression (Morley 2003; Rowan et al. 2004; King et al. 2009; Fig. 1). Gravitational potential of accumulating sediment on the delta top generates margin-parallel maximum horizontal stress (sH) orientations (extension), which are marked by margin-parallel-striking normal growth faults and have listric shapes (Mandl From: Healy, D., Butler, R. W. H., Shipton, Z. K. & Sibson, R. H. (eds) 2012. Faulting, Fracturing and Igneous Intrusion in the Earth’s Crust. Geological Society, London, Special Publications, 367, 141–153. http://dx.doi.org/ 10.1144/SP367.10 # The Geological Society of London 2012. Publishing disclaimer: www.geolsoc.org.uk/pub_ethics CYassirZKingetal.2009; Fig. 1). These extensional stresses drive downdip margin-normal sH orientations in the deepwater fold–thrust belt (or delta toe; compression), which are marked by margin-parallel-striking stacked thrust sheets and associated folds (Tingay et al. 2005; King et al. 2009; Fig. 1). However, the lobe shape of delta systems results in strike-slip stress regimes and associated structures at the outermost lateral margins of the systems (Peel et al. 1995). Present-day maximum horizontal stress orientations in the onshore Gulf Coast region display a clear margin-parallel trend (Tingay et al. 2006). However, margin-parallel sH orientations in the delta top region of the Gulf of Mexico, offshore Louisiana, demonstrate significant deflections from the expected margin-parallel sH orientations (Yassir & Zerwer 1997). Maximum horizontal stress orientations in the Gulf of Mexico, offshore Louisiana, are third-order sH orientations generated by the gravitational potential of the accumulating sediment in the delta systems. However, many of these third-order sH orientations are deflected around salt diapirs that are considered to be caused by the contrast between the geomechanical properties of the salt and adjacent clastic deltaic sediments (Bell 1996; Yassir & Zerwer 1997). However, the Gulf of Mexico stress analysis conducted by Yassir and Zerwer (1997) was primarily a two-dimensional study using only the map pattern of sH orientations and does not account for the vertical changes in geomechanical properties or diapir shape. In this paper, we present 5 new sH orientations determined from 8 petroleum wells. We present a 3D model of the deflected sH orientations around a salt diapir, demonstrating changes in the orientations both laterally and vertically, and discuss the causes of these deflections. Geological setting: the Gulf of Mexico The Gulf of Mexico is one of the world’s foremost petroleum provinces, and is located offshore the southern USA at 19–308N and 283 to 2978W (Fig. 2a). Water depths in the Gulf of Mexico range from several metres around the coasts to more than 2000 m in the deep central parts. Much of the petroleum exploration has been focused on the shallow-water petroleum-rich delta top (Trudgill et al. 1999). Exploration focus shifted in the last decade to the deep water, as major discoveries in the deepwater fold–thrust belts were made (Trudgill et al. 1999). However, exploration and major reserve development programs continue in both the delta top and deepwater fold–thrust belt regions at present day. The Gulf of Mexico is composed of several Upper Jurassic–Pleistocene delta systems that prograded from the north and west sourced by the Rio Grande (Galloway 1989; Fiduk et al. 1999; Fig. 2a). The delta systems sit on and above the Middle Jurassic Louann Salt, which is extensive across the northern Gulf of Mexico but is absent in the Mexican Ridges area (Peel et al. 1995; Trudgill et al. 1999). The Louann Salt forms the regional detachment zone beneath the deltaic sediments, with the majority of normal faults and thrust faults detaching at this level (Worrall & Snelson 1989; Fig. 1. Schematic diagram of a delta–deepwater fold–thrust belt illustrating the linked extension and compression. The delta top exhibits normal listric growth faults marking a margin-parallel maximum horizontal stress, and the delta toe (or deepwater fold–thrust belts) exhibits imbricate thrust sheets and associated fault-propagation folds marking a margin-normal maximum horizontal stress orientation (from King & Backe 2010). R. KING ET AL. 142

The Archaean to Mesoproterozoic basement of northern South Australia is almost completely overlain by thick Neoproterozoic and younger basins (<< 1% outcrop), yet is likely to preserve an important record of the interactions between the Archean-Proterozoic Gawler Craton and the Proterozoic Musgrave Province during the amalgamation of Australia in the Proterozoic. However, constraints on the location and geometry of the boundary between these provinces are poor. We use potential field data to determine the 3D basement architecture and so constrain where this Palaeo-Mesoproterozoic boundary may be located beneath the Eastern Officer Basin. We establish the geometry and properties of the overlying basins and explicitly include them during forward and inverse modelling of potential field data to highlight the structure of the underlying basement. Our analysis identifies three crustal domains. (1) Southeast of the steep northeast-southwest Middle Bore Fault, positive gravity and magnetic anomalies are co-located and sourced from bodies in the upper crust, these bodies overlie middle to lower crust that is apparently uniform. (2) Between the Middle Bore Fault and the southern edge of the Munyarai Trough, the highest amplitude gravity and magnetic anomalies are not co-located and are sourced from large northwest dipping bodies. (3) To the northwest, the crust underlying the Munyarai Trough has similar properties to the Musgrave Province, suggesting that the Musgrave Province extends at least 50 km beneath the Eastern Officer Basin. Although details of the geology in the second (central) domain are poorly constrained, the domain preserves large crustal-scale Precambrian structures and is interpreted to mark the boundary between the Gawler Craton and the Musgrave Province. In particular, the multiply reactivated Middle Bore Fault forms a major crustal boundary and is interpreted to mark the northern limit of the Gawler Craton. The Middle Bore Fault may have formed as early as the Kimban Orogeny (similar to 1.7 Ga), although substantial reactivation and modification of the crustal architecture could have occurred between the Kimban Orogeny and intrusion of the cross-cutting Gairdner Dolerite Dykes (827 Ma). Refereed/Peer-reviewed

Deepwater fold and thrust belts (DWFTBs) are classified into near-field stress-driven Type 1 systems confined to the sedimentary section, and Type 2 systems deformed by either far-field stresses alone, or mixed near- and far-field stresses. DWFTBs can occur at all stages of the Wilson cycle up to early stage continent continent collision. Type 1 systems have either weak shale or salt detachments, they occur predominantly on passive margins but can also be found in convergent-related areas such as the Mediterranean and N. Borneo. Examples include the Niger and Nile deltas, the west coast of Africa, and the Gulf of Mexico. Type 2 systems are subdivided on a tectonic setting basis into continent convergence zones and active margin DWFTBs. Continent convergence zones cover DWFTBs developed during continent–arc or continent–continent collision, and those in a deepwater intracontinental setting (e.g. W. Sulawesi, Makassar Straits). Active margins include accretionary prisms and transform margins. The greatest variability in DWFTB structural style occurs between salt and shale detachments, and not between tectonic settings. Changes in fold amplitude and wavelength appear to be more related to thickness of the sedimentary section than to DWFTB type. In comparison with shale, salt detachment DWFTBS display a lower critical wedge taper, more detachment folds, long and episodic duration of deformation and more variation in vergence. Structures unique to salt include canopies and nappes. Accretionary prisms also standout from other DWFTBs due to their relatively long, continuous duration, rapid offshore propagation of the thrust front, and large amount of shortening. In terms of petroleum systems, many similar issues affect all DWFTBs, these include: the oceanward decrease in heat flow, offshore increase in age of mature source rock, and causes of trap failure (e.g. leaky oblique and frontal thrust faults, breach of top seal by fluid pipes). One major difference between Type 1 and Type 2 systems is reservoir rock. High quality, continent-derived, quartz-rich sandstones are generally prevalent in Type 1 systems. More diagenetically reactive minerals derived from igneous and ophiolitic sources are commonly present in Type 2 systems, or many are simply poor in well-developed turbidite sandstone units. However, some Type 2 systems, particularly those adjacent to active orogenic belts are partially sourced by high quality continent-derived sandstones (e.g. NW Borneo, S. Caspian Sea, Columbus Basin). In some cases very high rates of deposition in accretionary prisms adjacent to orogenic belts, coupled with uplift due to collision, results in accretionary prism related fold belts that pass laterally from sub-aerial to deepwater conditions (e.g. S. Caspian Sea, Indo-Burma Ranges). The six major hydrocarbon producing regions of DWFTBs worldwide (Gulf of Mexico, Niger Delta, NW Borneo, Brazil, West Africa, S. Caspian Sea) stand out as differing from most other DWFTBs in certain fundamental ways, particularly the very large volume of sediment deposited in the basins, and/or the great thickness and extent of salt or overpressured shale sdetachments.

The Hammerhead Delta–Deepwater Fold-Thrust Belt is located in the Ceduna Sub-Basin of the Bight Basin, offshore southern Australia. It is synonymous with the Hammerhead Supersequence and consists of three, Campanian to Maastrichtian, deltaic sediment packages. The Hammerhead Delta–Deepwater Fold-Thrust Belt is a short-lived gravity-gliding system that exhibits a distinctive spoon-shape in cross-section. The system detaches on a master horizon at the top of the Tiger Formation. Finite Element Method based two-dimensional restorations show that the Hammerhead Delta–Deepwater Fold-Thrust Belt is a near-balanced system with near equal amounts of up-dip extension and down-dip compression. Overall, there is only 2.4% additional extension in the Hammerhead Delta–Deepwater Fold-Thrust Belt. This near-balanced system is unusual in comparison with other passive margin Delta–Deepwater fold-thrust belts, which generally demonstrate large amounts of extension compared with shortening, due to the regional-scale prograd...

Recent GPS measurements demonstrate that NW Borneo undergoes 4–6 mm of plate-scale shortening a year, which is not accommodated by plate-scale structures. The only geological structure in NW Borneo described to accommodate on-going shortening is the Baram Delta System located on the outer shelf to basin floor. Delta toe fold-thrust belts are commonly thought to be caused by margin-normal compressional stresses generated by margin-parallel upslope gravitational extension. The Baram Delta System is divided into three neotectonic provinces: 1) an inactive onshore and inner shelf region of inversion superimposed on an older extensional deltaic province, 2) an outer shelf region of present-day deltaic extension, and; 3) a compressional delta toe. However, it is uncertain whether compression in the delta toe area is purely driven by gravity (i.e. shortening is less than upslope extension) or if there is a component of regional shortening involved, which can only be demonstrated if shortening is greater than upslope extension. In order to quantify the balance between the shortening related to the upslope gravitational extension and the shortening related to the regional geodynamic framework in the Baram Delta System, we have used a geomechanical code based on the Finite Element Method and conservation of mass and momentum, Dynel 2D. This enabled us to reconstruct the tectonic evolution of the delta and to demonstrate for the first time that the total shortening observed in the delta toe does not balance against the active extension in the delta top; with the system exhibiting >1.8% shortening overall (or ∼2.0 km). This additional shortening is therefore attributed to plate-scale shortening across NW Borneo produced by far-field compression. Using a convergence rate of 4 mm y −1 , demonstrated by GPS measurements, the delta toe has accommodated far-field compression only in the last 0.5 My.

The Cuddapah Basin is one of a series of Proterozoic basins that overlie the cratons of India that, due to limited geochronological and provenance constraints, have remained subject to speculation as to their time of deposition, sediment source locations, and tectonic/geodynamic significance. Here we present 21 new, stratigraphically constrained, U-Pb detrital zircon samples from all the main depositional units within the Cuddapah Basin. These data are supported by Hf isotopic data from 12 of these samples, that also encompass the stratigraphic range, and detrital muscovite 40Ar/39Ar data from a sample of the Srisailam Formation. Taken together, the data demonstrate that the Papaghni and lower Chitravati Groups were sourced from the Dharwar Craton, in what is interpreted to be a rift basin that evolved into a passive margin. The Nallamalai Group is here constrained to be deposited between 1659±22Ma and ~1590Ma. It was sourced from the coeval Krishna Orogen to the east, and was deposited in its foreland basin. Nallamalai Group detrital zircon U-Pb and Hf isotope values directly overlap with similar data from the Ongole Domain metasedimentary rocks. Depositional age constraints on the Srisailam Formation are permissive with it being coeval with the Nallamalai Group and it was possibly deposited within the same basin. The Kurnool Group saw a return to Dharwar Craton derived provenance and is constrained to being Neoproterozoic. It may represent deposition in a long-wavelength basin forelandward of the Tonian Eastern Ghats Orogeny. Detrital zircons from the Gandikota Formation, which is traditionally considered a part of the Chitravati Group, constrain it to being deposited after 1181±29Ma, more than 700Ma after the lower Chitravati Group. It is possible that the Gandikota Formation is correlative with the Kurnool Group.The new data suggest that the Nallamalai Group correlates temporally and tectonically with the Somanpalli Group of the Pranhita-Godavari Valley Basin, which is tightly constrained to being deposited at ~. 1620. Ma. These syn-orogenic foreland basin deposits firmly link the SE India Proterozoic basins to their orogenic hinterland with their discovery filling a 'missing-link' in the tectonic development of the region. Refereed/Peer-reviewed

The geometry of tectonic structures, attributed to the Neogene–Quaternary time interval, is described in the active setting of the Venezuelan Andes. Our methodology is based on the analysis of radar satellite and Digital Elevation Model imagery, complemented by structural fieldwork and the compilation of seismotectonic data to make a structural analysis on a regional scale. Radar images provide first class data for morphostructural analysis in areas of dense vegetation and frequent cloud covering, like the Venezuelan Andes. We focused our analysis in the Burbusay–Rio Momboy and Bocono faults corner located in the central part of the belt. We have described three stages of deformation during the Neogene–Quaternary. The first one, Mio-Pliocene in age, is a NW–SE compression responsible for the uplift of the Venezuelan Andes. The second tectonic stage corresponds to a strike-slip regime of deformation marked by shearing along the Bocono, Burbusay and Valera faults, which separates two triangular wedges in the larger Trujillo block. This strike-slip faulting-dominated compressional-extensional tectonic regime allowed the Trujillo crustal block to move towards the NE. Wrenching has therefore started at some point between the Pliocene and the Quaternary. These two tectonic events are consistent with ongoing strain partitioning in the Venezuelan Andes. The third stage corresponds to extensional deformation limited to the Trujillo block and is still active today. Extension is associated with the motion of crustal blocks moving relative to each other, probably above the upper-lower crust boundary. Such extensional deformation can be understood considering that the crust extends and stretches at the same time as it moves towards the NE. The combination of both horizontal lateral motion and extension is characteristic of a tectonic escape process. The northeastward escape of the Trujillo block, which belongs to the larger North Andes block, occurs as a result of the combination of the NW–SE intracontinental convergence between the South-American plate and the Maracaibo block, and the presence to the north of the Caribbean oceanic plate considered as a free boundary. We have showed that the kinematics of the Caribbean plate offers not only a favorable environment, but may also be considered as the driving force of the tectonic escape of the North Andes block.

The geometry of extensional structures is described for the first time in the active setting of the Venezuelan Andes using remote sensing imagery. We favored the use of a mosaic of Synthetic Aperture Radar (SAR) scenes of the Japanese Earth Resources Satellite-1 (JERS-1) assisted by complementary remote sensing devices (Landsat TM, digital elevation models) and field observations to make a structural analysis at regional scale. Radar images are particularly efficient in the Venezuelan Andes where dense vegetation and frequent cloud covering earlier lent difficulties to remote sensing studies. We focused our analysis in the Valera–Rio Momboy and Bocono faults corner and in the Mucujun area. We show that, in an area where ongoing compression and strike–slip deformations occur, brittle extension can be detected independently from previous knowledge. Extensional structures correspond to elongated tilted blocks with dimension less than 10 km in width. Blocks are bounded by curved faults in plan view, the concavity being turned towards the axial part of the belt. The geometry and kinematics of such structures suggest that syn-orogenic extension started together with initiation of right-lateral strike–slip motion along the Bocono Fault in the Plio-Quaternary.

The bulk of the electricity supply to the state of Victoria, SE Australia, is generated by brown-coal fired power plants, most of which are located within the Latrobe Valley of the Gippsland Basin. Geological storage of carbon dioxide is has the potential

The Adelaide Basin in Australia is a complex of late Neoproterozoic to Early Cambrian rift and sag basins which was inverted during the Cambro-Ordovician Delamerian Orogeny. The deposition of evaporitic sediments during the earliest stage of basin development in the late Neoproterozoic (Willouran age) played a major role in the subsequent tectonic evolution of the basin. Previous studies have shown that early mobilization, vertical transport and withdrawal of the evaporites influenced the sedimentation during the late Neoproterozoic and Early Cambrian. The evaporites also influenced deformation during the inversion of the basin and the development of the Delamerian fold and thrust belt. However, the control exerted by basement structures in the deposition of the evaporitic beds and the role of these tectonic structures in the later inversion of the basin have been poorly constrained. In this work, we use a combination of published and original geological observations along with the interpretation of potential field datasets (total magnetic intensity and Bouguer anomaly data) to better constrain the geology of the basin at depth. We construct two and a half dimensional forward models of the potential field data along selected profiles across the Adelaide Basin. These models are constrained by the geology at the surface, drill hole data and measured petrophysical properties (specific gravity and magnetic susceptibility). We achieved the best fit between observed and modelled potential fields with a model favouring thick-skinned deformation, where the diapirs are not randomly distributed, but located directly above basement-penetrating normal faults. Furthermore, these normal faults were probably active during the sedimentation of the late Neoproterozoic and Early Cambrian sediments, and underwent partial or total inversion during the Cambro-Ordovician Delamerian Orogeny. Mobilisation and withdrawal of the evaporites was therefore initiated and facilitated by the extension coeval with the opening of the basin, and continued during the subsequent Delamerian Orogeny. Refereed/Peer-reviewed

Declining conventional hydrocarbon reserves have triggered exploration towards unconventional energy, such as CSG, shale gas and enhanced geothermal systems. Unconventional play viability is often heavily dependent on the presence of secondary permeability in the form of interconnected natural fracture networks that commonly exert a prime control over permeability due to low primary permeabiliy of in situ rock units. Structural permeability in the Northern Perth, SA Otway, and Northern Carnarvon basins is characterised using an integrated geophysical and geological approach combining wellbore logs, seismic attribute analysis and detailed structural geology. Integration of these methods allows for the identification of faults and fractures across a range of scales (millimetre to kilometre), providing crucial permeability information. New stress orientation data is also interpreted, allowing for stress-based predictions of fracture reactivation. Otway Basin core shows open fractures are rarer than image logs indicate; this is due to the presence of fracture-filling siderite, an electrically conductive cement that may cause fractures to appear hydraulically conductive in image logs. Although the majority of fractures detected are favourably oriented for reactivation under in situ stresses, fracture fill primarily controls which fractures are open, demonstrating that lithological data is often essential for understanding potential structural permeability networks. The Carnarvon Basin is shown to host distinct variations in fracture orientation attributable to the in situ stress regime, regional tectonic development and local structure. A detailed understanding of the structural development, from regional-scale (hundreds of kilometres) down to local-scale (kilometres), is demonstrated to be of importance when attempting to understand structural permeability.

The Rosedale Fault System (RFS) bounds the northern margin of the Gippsland Basin on the Southern Australian Margin. It comprises an anastomosing system of large, Cretaceous-age normal faults that have been variably reactivated during mid Eocene-Recent inversion. A number of large oil and gas fields are located in anticlinal traps associated with the RFS, and in the future these fields may be considered as potential storage sites for captured CO2. Given the evidence for geologically recent fault reactivation along the RFS, it is thus necessary to evaluate the potential impacts of CO2 injection on fault stability. The analysis and interpretation of 3D seismic data allowed the authors to create a detailed structural model of the western section of the RFS. Petroleum geomechanical data indicates that the in-situ stress in this region is characterised by hybrid strike-slip to reverse faulting conditions where SHmax (40.5 MPa/km) > SV (21 MPa/km) ~ Shmin (20 MPa/km). The authors performed geomechanical modelling to assess the likelihood of fault reactivation assuming that both strike-slip and reverse-stress faulting regimes exist in the study area. The authors’ results indicate that the northwest to southeast and east-northeast to west-southwest trending segments of the RFS are presently at moderate and high risks of reactivation. The authors’ results highlight the importance of fault surface geometry in influencing fault reactivation potential, and show that detailed structural models of potential storage sites must be developed to aid risk assessments before injection of CO2.

Understanding natural fracture networks has increasingly been recognised as an important factor for the prospectivity of a geothermal play, as they commonly exert a prime control over permeability at depth. 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. 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. Geothermal energy prospectivity in the region will therefore depend heavily on similar engineering techniques or on the presence of secondary permeability due to interconnected natural fractures. The existence and extent of these natural fractures are 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 are 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 leak off tests from 13 petroleum wells are used to constrain the present-day stress magnitudes, giving a transitional strike-slip fault to reverse-fault stress regime in the Northern Perth Basin. 870 fractures are identified in image logs from 13 petroleum wells in the Northern Perth Basin, striking roughly north to south and northwest to northeast. Fractures aligned in the present-day stress field are optimally oriented for reactivation, and are hence likely to be open to fluid flow. Electrically resistive and conductive natural fractures are 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 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, and so are likely to be open to fluid flow. This is reinforced by the correlation of drilling fluid loss and conductive natural fractures in three wells in the Northern Perth Basin. To gain an understanding of the extent and interconnectedness of these fractures, it is necessary to look at more regional data, such as 3D seismic surveys. It is, however, well-documented that fault and fracture networks like those generally observed in image logs lie well below seismic amplitude resolution, making them difficult to observe directly on amplitude data. 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 across much of the basin. These optimally oriented fractures are therefore likely to form a secondary permeability network throughout the cemented sediments of the Northern Perth Basin, offering potential deep fluid flow conduits, which may be exploited for the production of geothermal energy.

One of the main risks associated with the underground storage of CO2 is the possibility of leakage from the reservoir to the surface. Among the most likely pathways for CO2 migration are permeable fault systems and highly fractured caprocks. It is thus important to develop a detailed understanding of geometrical characteristics of fault systems to assess the long-term storage and reactivation potential of fault dependent reservoirs. This extended abstract describes the results from a detailed structural analysis of the Rosedale Fault System (RFS) in the Gippsland Basin, Victoria, which is undergoing assessment for CO2 storage, using high-fidelity 3D seismic data. The RFS is a long-lived fault system that has experienced significant reactivation since the late Miocene and continued activity on this fault. Conventional structural mapping has been supported by seismic attribute analyses using a dip-steering cube. The coupling of seismic attribute analysis with fault displacement analysis has enabled the geometry of the RFS to be defined and to delineate associated damage zone. This extended abstract's analysis shows that the RFS is an anastomosing normal fault system that displays lateral changes in the degree of late Miocene-onwards reverse reactivation, which has affected the Latrobe Group and older units. This analysis has also revealed an extensive polygonal fault-system confined to post-Top Latrobe (Eocene) sediments, showing that this component of the stratigraphy is structurally decoupled from the older sedimentary section. This extended abstract concludes by assessing the roles that both the RFS and the polygonal fault system play in fluid migration in the western Gippsland Basin.

Previous in-situ stress studies across many of Australia’s petroleum basins demonstrate normal fault and strike-slip fault stress regimes, despite the sedimentary successions demonstrating evidence for widespread Miocene-to-Recent reverse faulting. Seismic and outcrop data demonstrate late Miocene-to-Recent reverse or reverse-oblique faulting in the Otway and Gippsland basins. In the Otway Basin, a series of approximately northeast to southwest trending anticlines related to reverse-reactivation of deep syn-rift normal faults, resulting in the deformation of Cenozoic post-rift sediments are observed. Numerous examples of late Miocene-to-Recent reverse faulting in the offshore Gippsland Basin have also been observed, with contractional reactivation of previously normal faults during these times partially responsible for the formation of anticlinal hydrocarbon traps that host the Barracouta, Seahorse and Flying Fish hydrocarbon fields, adjacent to the Rosedale Fault System. A new method for interpreting leak-off test data demonstrates that the in-situ stress data from parts of the Otway and Gippsland basins can be reinterpreted to yield reverse fault stress regimes, consistent with the present-day tectonic setting of the basins. This reinterpretation has significant implications for petroleum exploration and development in the basins. In the Otway and Gippsland basins, wells drilled parallel to the orientation of the maximum horizontal stress (σH) represent the safest drilling directions for both borehole stability and fluid losses. Faults and fractures, striking northeast to southwest, previously believed to be at low risk of reactivation in a normal fault or strike-slip fault stress regime are now considered to be at high risk in the reinterpreted reverse fault stress regime.

The future success of both enhanced (engineered) geothermal systems and shale gas production is reliant on the development of reservoir stimulation strategies that suit the local geo-mechanical conditions of the prospects. The orientation and nature of the in-situ stress field and pre-existing natural fracture networks in the reservoir are among the critical parameters that will control the quality of the stimulation program. This study provides a detailed investigation into the nature and origin of natural fractures in the area covered by the Moomba–Big Lake 3D seismic survey, in the southwest termination of the Nappamerri Trough of the Cooper Basin. These fractures are imaged by both borehole image logs and complex multi-traces seismic attributes (e.g. dip-steered most positive curvature and dip-steered similarity), are pervasive throughout the cube, and exhibit a relatively consistent northwest–southeast orientation. Horizon extraction of the seismic attributes reveal a strong variation in the spatial distribution of the fractures. In the acreage of interest, fracture density is at its highest in the vicinity of faults and on top of tight antiforms. This study also suggests a good correlation between high fracture density and high gamma ray values. The correlation between high fracture density and shale content is somewhat counterintuitive, as shale is expected to have a higher tensile and compressive strengths at shallow depths and typically contain fewer fractures (Lin, 1983). At large depths, however—and due to sandstone diagenesis and cementation—shale has lower tensile and compressive strength than sandstone and is expected to be more fractured (Lin, 1983). A similar correlation has been noted in other Australian Basins (e.g. Northern Perth Basin). Diagenetic effects, pore pressure, stiffness, variations in tensile versus compressive strength of the shale and the sandstone may explain this disparity.

In this paper, different 3D seismic attributes calculated to improve the accuracy and robustness of structural interpretations in several energy-rich Australian basins are compared. Detailed and precise fault and fracture maps are crucial not only for initial petroleum play assessment, but also for fault seal analysis and reservoir integrity studies. Robust fault and fracture models are also needed to improve the design of reservoir simulation programs and to manage the long-term containment of gas in geological formations. Different attributes (including coherency, dip-steered similarity, dip-steered median filter, dip-steered variance, apparent dip, and dip-steered most-positive and most-negative curvatures) from an array of 3D seismic datasets to better image structural fabrics, such as normal and different fractures patterns, in the North Perth, Cooper, Ceduna, Otway and Gippsland basins have been calculated. The results provide a remarkable improvement in the quality and precision of structural maps using this multi-attribute mapping workflow by comparison with more conventional maps produced, solely using seismic amplitude data. The key to the successful application of multi-attribute structural analysis, however, remains with the ability of the interpreter to identify meaningful structural information from a large volume of data. Thus, the structural expertise of the interpreter remains as the cornerstone to making geological sense of the various seismic processing techniques available.

The success story of a shale-gas reserve development in the United States is triggering a strong industry focus towards similar plays in Australia. The Cooper Basin (located at the border of South Australia and Queensland) and the Otway Basin (extending both onshore and offshore South Australia and Victoria) could be prime targets to develop shale-gas projects. The Cooper Basin, a late-Carboniferous to mid-Triassic basin, is the largest onshore sedimentary basin producing oil and gas from tight conventional reservoirs with low permeability. Fracture stimulation programs are used extensively to produce the oil and gas. Furthermore, new exploration strategies are now targeting possible commercial gas hosted in low-permeability Permian shale units. To maximise production, the development of shale-gas prospects requires a good understanding of the: 1. structure of the reservoirs; 2. mechanical properties of the stratigraphy; 3. fracture geometry and density; 4. in-situ stress field; and, 5. fracture stimulation strategies. In this study, we use a combination of seismic mapping techniques–including horizon and attribute mapping, and an analysis of wellbore geophysical logs–to best constrain the existing fracture network in the basins. This study is based on the processing and analysis of a 3D seismic cube–the Moomba Big Lake survey–which is located in the southwestern part of the Cooper Basin. This dataset covers an area encompassing both a structurally complex setting in the vicinity of a major fault to the SE of the survey, and an area of more subtle deformation corresponding to the southernmost part of the Nappamerri Trough. Structural fabrics trending ˜NW–SE and NE–SW, which are not visible on the amplitude seismic data, are revealed by the analysis of the seismic attributes–namely a similarity (equivalent to a coherency cube), dip steering and maximum curvature attributes. These orientations are similar to those of natural fractures mapped from borehole images logs, and can therefore be interpreted as imaging natural fractures across the Moomba-Big Lake area. This study is the first of its kind able to detect possible fractures from seismic data in the Cooper Basin. The methodology developed here can offer new insights into the structure of sedimentary basins and provide crucial parameters for the development of tight reservoirs. In parallel, a tentative forward model of the generation of a fracture network following a restoration of the Top Roseneath horizon was carried out. The relatively good correlation between the fracture orientations generated by the model and the fractures mapped from geophysical data shows that fractures in the Moomba-Big Lake area may have formed during either a N–S compressive principal horizontal stress, or an E–W compressive principal horizontal tectonic stress regime. In addition, the orientations of the fracture interpreted through this study are also compatible with a generation under the present day stress regime described in this part of the basin, with an maximal horizontal stress trending E–W.

The Hammerhead Delta—deepwater fold-thrust belt is located in the Ceduna Sub-basin of the Bight Basin, offshore southern Australia. It is a short lived gravity gliding system, Late Santonian-Maastrichtian in age. It exhibits a distinctive spoon shape in cross-section and detaches on a master horizon above Santonian marine shales of the Tiger Supersequence. Here, we have interpreted a large seismic dataset—including the recently acquired regional two-dimensional seismic dataset provided by Ion Geophysical—to constrain the regional structural geometry of the Hammerhead Delta—deepwater fold-thrust belt. Two structural restorations were completed to quantify the amount of extension and shortening in the system. These restorations were: a two-dimensional kinematic restoration, using 2D MOVE; and a two-dimensional geomechanical restoration, using Dynel 2D. By comparing results from the two techniques we demonstrate that the amount of observed extension in the delta top is nearly balanced by the shortening in the delta toe. The near balance (< 2 % excess extension) of the system is a unique result. Other passive margin systems demonstrate larger amounts of extension compared to shortening, due to the regional-scale pro-gradational nature of the systems. These results suggest that the balanced geometry of the Hammerhead Delta—deepwater fold-thrust belt is consistent with either a sudden decrease in sediment supply during the upper Maastrichtian, resulting in a cessation of prograding fault activity, or a loss of extension to the underlying Cenomanian growth faults or some combination thereof. Thus, the system failed to develop into an extensive passive margin delta—deepwater fold-thrust belt.

Potential shale gas bearing basins in SA are primarily dominated by thermogenic play types and span the Neoproterozoic to Cretaceous. Whilst companies have only recently commenced exploring for shale gas in the Permian Cooper Basin, strong gas shows have been routinely observed and recorded since exploration commenced in the basin in 1959. The regionally extensive Roseneath and Murteree shales represent the primary exploration focus and reach maximum thicknesses of 103 m and 86 m respectively with TOC values up to 9%. These shales are in the gas window in large parts of the basin, particularly in the Patchawarra and Nappamerri troughs. Outside the Cooper Basin, thick shale sequences in the Crayfish Subgroup of the Otway Basin, in particular the Upper and Lower Sawpit shales and to a lesser extent the Laira Formation, have good shale gas potential in the deeper portions of the basin. TOC averages up to 3% are recorded in these shales in the Penola Trough; maturities in the range of 1.3–1.5% have been modelled. Thick Permian marine shales of the Arckaringa Basin have excellent source rock characteristics, with TOC’s ranging 4.1–7.4% and averaging 5.2% over an interval exceeding 150 m in the Phillipson Trough; however, these Type II source rocks are not sufficiently mature for gas generation anywhere in the Arckaringa Basin. Shale gas has the potential to rival CSM in eastern Australia; its potential is now being explored in SA.

We present results from a margin-wide analysis of the history of post-breakup Cenozoic compressional deformation and related exhumation along the passive southern margin of Australia, based on a regional synthesis of seismic, stratigraphic and thermochronological data. The Cenozoic sedimentary record of the southern margin contains regional unconformities of intra-Lutetian and late Miocene–Pliocene age, which coincide with reconfigurations of the boundaries of the Indo-Australian Plate. Seismic data show that post-breakup compressional deformation and sedimentary basin inversion—characterised by reactivation of syn-rift faults and folding of post-rift sediments—is pervasive from the Gulf St Vincent to Gippsland basins, and occurred almost continually since the early- to mid-Eocene. Inversion structures are absent from the Bight Basin, which we interpret to be the result of both the unsuitable orientation of faults for reactivation with respect to post-breakup stress fields, and the colder, stronger lithosphere that underlies that part of the margin. Compressional deformation along the southeastern margin has mainly been accommodated by reactivation of syn-rift faults, resulting in folds with varying ages and amplitudes in the post-rift Cenozoic succession. Many hydrocarbon fields in the Otway and Gippsland basins are located in these folds, the largest of which are often associated with substantial localised exhumation. Our results emphasise the importance of constraining the timing of Cenozoic compression and exhumation in defining hydrocarbon prospectivity of the southern margin.

GeoScience Victoria and partners have undertaken the first detailed basin-wide study of the regional top seal in the Gippsland Basin. The Gippsland Basin is an attractive site for geological carbon storage (GCS) because of the close proximity to emission sources and the potential for large-scale storage projects. This top seal assessment involved the analysis of seal attributes (geometry, capacity and mineralogy) and empirical evidence for seal failure (soil gas geochemical anomalies, gas chimneys, hydrocarbon seepage and oil slicks). These datasets have been integrated to produce a qualitative evaluation of the containment potential for GCS, and also hydrocarbons, across the basin. Mineralogical analysis of the top seal has revealed that the Lakes Entrance Formation is principally a smectite-rich claystone. The geometry of the top seal is consistent with deposition in an early post-rift setting where marine sediments filled palaeo-topographic lows. The seal thickness and depth to seal base are greatest in the Central Deep and decrease toward the margins. There is a strong positive relationship between seal capacity column heights, seal thickness, depth to seal base and smectite content. At greater burial depths (below 700 m) and where smectite content is greater than 70%, seal capacity is increased (supportable column heights above 150 m). Natural hydrocarbon leakage and seepage onshore and offshore is correlated with fault distribution and areas of poor seal capacity. This study provides a framework for qualitatively evaluating seal potential at a basin scale. It has shown that the potential of the regional top seal over the Central Deep, Southern Terrace, central eastern Lake Wellington Depression and the southern to central near shore areas in the Seaspray Depression are most suitable for the containment of supercritical CO2. Further toward the margin of the regional seal in both onshore and offshore areas, containment of supercritical CO2 is less likely.

Carbon capture and storage (CCS) will not reach its full greenhouse gas emissions mitigation potential without harnessing the vast storage resource thought to exist within deep saline formations. These formations occur within most sedimentary basins and are defined, in part, by containing interstitial formation fluid that is unfit or uneconomic for current or future use. Though parts of deep saline sedimentary successions may be well understood, most have not been characterized in detail for CO 2 storage. Knowledge of critical reservoir parameters is therefore usually insufficient to accurately define storage systems within them at the range of spatial and temporal scales required for a CO 2 injection site. Previous reconnaissance studies are a useful starting point for CO 2 storage system appraisal where exploration survey data exists. This study screens likely storage locations within the onshore Gippsland Basin in eastern Victoria, southeastern Australia. The most prospective system is close to industrial CO 2 emissions nodes and comprises suitable stratigraphy at appropriate depth. However, new geological characterization suggests existing interpretations are unsatisfactory and the opportunity for CO 2 storage there may be more limited and challenging than initially thought.